4.4 Reuse of Existing Infrastructure
Numerous studies have been completed focusing on the reuse of existing pipelines and platforms for offshore applications of transport and storage of CO281,82. The key issues here are the timely availability of such a piece of infrastructure and transporting a fluid for which the original equipment was not designed.
With respect to availability, pipeline owners prefer an additional high value supply they can contract to deliver rather than a low value commodity such as CO2. If available, then any plan to use an existing pipeline will require extensive investigation into the suitability of the pipeline and an assessment level of degradation. Additionally, pipelines may not have been originally designed for the high pressures desired for a CO2 transport infrastructure. However, if it is practical to use such a facility, it could significantly reduce the overall cost associated with transportation of CO2 to a specific area.
Obtaining an existing platform for use in storing CO2 is more difficult. Platforms are subject to stringent decommissioning rules. In some countries, transferring these obligations to new owners may require changes to rules, regulations and even laws. There may need to be a change in purpose and a re-allocation of risks, responsibilities and liabilities.
The life expectancy of platforms will also be a key factor in assessing their suitability. Most offshore platforms were designed for their initial field development. Many have had additional loads added to bring on board satellite well operations, thereby increasing the economic usefulness of the platform. If significant amounts of process equipment are able to be removed from an existing platform, thereby reducing the loading on the structure, it may be possible to extend further the useful service life of a platform that has already exceeded its original design life. As with the reuse of pipeline infrastructure, this will have to be carefully assessed but may be a significant means of reducing the costs of CCS. In addition, it may provide an income stream to help fund future 'decommissioning costs'.
The possibilities for deploying offshore installations for CCS service are varied, with some of the main scenarios being the use of:
- An existing installation which is still producing (especially those that are close to end of field economic life and would benefit from EOR).
- An existing installation which has a fixed decommissioning date.
- New installation specifically designed for storage service.
- As above but adjacent to an existing platform.
- Tie-in to an existing CCS system or facility.
However, there are many associated factors that need to coalesce successfully, including,type, condition of wells, location relative to onshore carbon capture plant, water depth (especially for a new-build) and the availability of power, should this be required. Existing installations offer a number of potential advantages:
- The ability to install equipment and power for pumping facilities.
- Potential availability of process heating.
- Ease of performing well maintenance and work-over operations.
In the UK offshore sector, clearly the platforms closest to shore, such as those located in the southern North Sea, will have significant advantages over those in the northern North Sea which are further from shore and in deeper waters. However, for EOR purposes, oil production is generally from central and northern North Sea sectors.
Most of the older installations and their equipment are currently subjected to life extension programmes involving equipment review and repainting programmes in order to maintain structural and process integrity, as is required to be demonstrated to the UK HSE. Should such facilities be taken over for CCS service, then this regime will need to be continued, albeit with less process equipment, especially if hydrocarbon production has ceased. Where EOR is to be implemented, the normal production facilities will be retained; hence, the platform will need to be able to accommodate additional equipment requiring any attendant weight, space and structural challenges to be overcome.
Redevelopment, of a particular platform will require a thorough review of the 83.and if required, modifications should be made to address any revealed reduction in operational safety or structural integrity. Another major consideration is whether the installation needs to be normally attended. Guidance on such installations is available
The safety case review should cover many aspects and the following are examples of the additional CO2-related items likely to be included:
- Identification of credible CO2 release scenarios.
- CO2 dispersion modelling studies.
- Ventilation of enclosed spaces.
- Review of safety critical elements.
- Emergency plans and evacuation procedures.
- Deployment of gas detection equipment and personal dosimeters.
- Suitability of safe refuges.
- Proximity of pipelines (e.g. risers) to safety-critical equipment.
- The potential for CO2 leaks to result in the cooling and consequential embrittlement of structural components.
- Arrangements for venting of CO2, both routinely and in an emergency.
- Operator training.
4.4.2 Implications for storage
The pipeline designer should be aware of the type of store into which the CO2 will be injected, since failure to appreciate the differences in these can lead to an increased hazard in the overall chain.
188.8.131.52 Depleted gas fields
There are two approaches to the storage of CO2 in depleted gas fields which will require very different operational management. One favours liquid CO2 injection from the outset when depleted gas field pressures allow it. The other approach starts with gaseous injection of CO2 until field pressure is sufficient to maintain a liquid column of CO2 in the well bore.
While the first case can easily receive liquid CO2, in the second case some projects have proposed gaseous transport of the CO2 to offshore facilities during these early periods. However, this involves large diameter pipelines and maintaining the CO2 pressure at less than 35 bar to avoid the risk of hydrate formation even with extremely dry CO2. The alternative is to let down the pressure of the liquid CO2 to gaseous conditions offshore which will most likely require offshore reheating of the CO2 to overcome the JT cooling effects (see 184.108.40.206), and may prove to be costly with respect to energy demands. Again, hydrate formation may occur from the offshore platform to the injection well due to pressure and temperature conditions within the injection line. However, in gas fields where field pressure has been depleted to very low levels, gaseous injection may be the only alternative until higher field pressures are established84,85,86. The pipeline designer will need to be aware that the pipeline may be required to handle both liquid and gaseous CO2, and have to cope with the transition between the two, with their very different properties and hazards
220.127.116.11 Depleted oil fields
The storage of CO2 in depleted oil fields does not raise the same concerns as for a depleted gas field, because the field pressures are never reduced to such levels as to be unable to maintain a liquid leg of CO2 within the well bore. While it may be cost effective to use existing platform facilities and existing wells for injection into a depleted oil field, decommissioned oil fields have a greater potential to be satisfactory storage complexes for CO2 and may require only a subsea facility monitored from shore or another platform or minimum facilities platform to control the flows of CO2 stored.
In using existing oil field platforms, the issues mentioned in section 4.3.3 should be taken into account. While hydrocarbon platform operators may be familiar with handling highly flammable produced fluids, CO2 has an entirely different hazard potential and the modifications to the platform and operating procedures should accommodate such factors.
If properly considered and implemented, whether the platform is attended or unattended, existing injection facilities offer a number of positive aspects:
- The ability to raise the pressure from delivered trunkline pressures if it is required to pump CO2 into the respective field.
- Existing utilities would be available to power any CO2 pumps.
- Working from a platform, it should be easier to complete any maintenance on wells and to complete any required workovers for existing wells.
18.104.22.168 Saline formations
Like the storage of CO2 in depleted oil fields, the reuse of existing facilities to store CO2 in saline formations does not raise the same concerns as for a depleted gas field. This is because the pressures within the formations are at or above the hydrostatic head for the depth of the formation, or approximately 1 bar for each 10 m, and provided the formation is below 800 m, the pressure should be sufficient to maintain the CO2 in the dense or supercritical phase within the well bore and formation. Again, it should be cost effective to use existing platform facilities to reach a nearby formation for CO2 injection for the reasons mentioned, but many saline formations will not have existing platforms nearby. These facilities will require subsea connections with control tie backs to existing facilities or minimum facilities platforms87 on top of the saline formation to safely support and control CO2 injections.
81 Report of the North Sea Basin Task Force, Development of a CO2 Transport and Storage Network in the North Sea, November 2007.
82 Rotterdam Climate Initiative, CO2 Capture, Transport and Storage in Rotterdam, 2009.
83 Energy Institute Guidelines for offshore oil and gas installations that are not permanently attended
84 SPE 123788, CO2 Injection into Depleted Gas Reservoirs, September 2009.
85 UK Carbon Capture and Storage Demonstration Competition, UKCCS - KT - S7.18 - Shell – 003, Flowline Well Interactions, April 2011, Scottish Power CCS Consortium
86 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
87 A platform similar to that shown in Figure A.4.7