Offshore CO 2 storage – description

Oil & gas have been produced from the Danish North Sea since the early 70s, and some of the fields are ap-proaching end of field life while others are expected to continue production until the end of the current con-cession.

The largest theoretical storage capacity would probably be in some of the very large chalk structures, which have been producing since the early 80s. Several of these fields are still operating or, in the case of the Tyra gas field, are currently being redeveloped. Repurposing some of the smaller, non-commercial chalk fields or suita-ble parts (e.g. long horizontal wells and wellhead platforms) of some of the larger chalk fields may well provide an attractive option for the utilisation of the storage capacity of the North Sea chalk reservoirs.

The focus in this report will be on the depleted northern sandstone fields, which at this point in time are con-sidered more readily available for timely development of geological CO2 storage.

The northern fields are either developed as standalone wellhead platforms or as integrated facilities with wells, process plant and accommodation; however, for this exercise these are assumed to be converted to unmanned installations.

Both the storage capacity, well tubing material and remaining lifetime vary from field to field, a factor which needs to be taken into consideration when developing a generic case. The cases below are not tailored towards one solution or operator, but known limitations are considered in order to be realistic.

Typical design lifetime of offshore production facilities are around 25 years; however, it is realistic to assume that the lifetime can be significantly increased. The first platforms in the Danish North Sea were installed in the early 70s and are after 50 years still in service and considered safe to operate. The actual lifetime of an offshore CO2 storage facility may to a higher degree also be dictated by the available storage capacity.

Base case for the well conversion is that well tubing in contact with reservoir fluids must be converted to cor-rosion resistant material due to the risk of corcor-rosion when CO2 is mixed with saline formation water.

1.3.1 1 Mt/year offshore CO² storage

Figure 0-24: 1 Mt/year offshore storage facility

It is expected that 1 Mt of CO2 per year can be injected into one depleted oil or gas field or a sector in a larger field. This will require conversion of a minimum of two wells and a third will be converted for redundancy. An additional well will be converted for use as an observation well equipped with down-hole pressure gauges.

It is expected that existing manifold and flowlines are reused to the extent possible limiting the platform mod-ifications mainly to installation of a new riser for import of CO2 from the loading boy.

CO2 is expected to be supplied to the field in a CO2 shuttle tanker with 20,000 tonnes capacity. In addition to operating as shuttle tanker, the vessel will also accommodate the CO2 injection facilities where the CO2 is heated and pressurised to the required injection pressure in order to allow direct injection of CO2 on the wellhead platform.

CO2 will be offloaded through a loading boy system (SAL/SBM) located approx. 3 km from the wellhead platform and transferred to the wellhead platform through a pipeline.

1.3.2 3 Mt/year offshore CO² storage

Figure 0-25: 3 Mt/year offshore storage facility

It is expected that 3 Mt of CO2 per year can be injected into one larger or two smaller depleted oil or gas reser-voirs or sectors. For this generic case, two depleted reserreser-voirs or sectors are assumed, but that an existing interfield pipeline can be used to transfer the CO2.

This will require conversion of a minimum of six wells and a seventh will be converted for redundancy. An additional well will be converted for use as an observation well equipped with down-hole pressure gauges.

It is expected that the existing manifold and flowlines are reused to the extent possible limiting the platform modifications mainly to the installation of a new riser for import of CO2.

CO2 is expected to be supplied to the field in shuttle tanker(s) and via a bow loading system loaded to a perma-nently moored vessel with up to 30.000 tonnes capacity, operating as a floating storage unit (FSU) and also accommodating the CO2 injection facilities. Using a permanently moored FSU injection facilities is considered more cost-effective and operational than having multiple shuttle tankers each with dedicated injection facili-ties.

The FSU will have a turret mooring system, which will allow transfer of CO2 to the wellhead platform through an approx. 3 km long pipeline.

1.3.3 5 Mt/year offshore CO2 storage

Figure 0-26: 5 Mt/year offshore storage facility

451 CO2 storage

It is expected that 5 Mt of CO2 per year can be injected into one larger or several smaller depleted oil or gas reservoirs or sectors. For this generic case, three depleted reservoirs or sectors are assumed. Two existing well-head platforms are assumed to be reused, and for the third field a new wellwell-head platform will be installed to provide sufficient lifetime. It is assumed that existing interfield pipelines can be used for the transfer of CO2. In total, 11 wells are assumed to be required, six conversions and five new. An additional well will be converted for use as an observation well equipped with down-hole pressure gauges.

For the existing wellhead platforms, it is expected that existing manifold and flowlines are reused to the extent possible limiting the platform modifications mainly to the installation of a new riser for the import of CO2. CO2 is expected to be supplied to the field in shuttle tanker(s) and via a bow loading system loaded to a perma-nently moored vessel with up to 50,000 tonnes capacity, operating as a floating storage unit (FSU) and also accommodating the CO2 injection facilities.

The FSU will have a turret mooring system, which will allow transfer of CO2 to the wellhead platform through an approx. 3 km long pipeline.

1.3.4 Typical timeline for an offshore CO² storage

Year Activity

1 Evaluation of exiting production and seismic data

Conceptual studies for facilities and purpose-built CO2 Carrier/Stor-age Unit

2 Environmental impact assessment, public hearings and approvals FEED studies, including life-time extension studies

Baseline studies

Final Investment Decision

3-4 Construction of purpose-built CO2 Carrier/Storage Unit Installation of mooring and loading system

Modification of existing well platform Conversion of first injection wells 5-6 Commence Injection CO2

Evaluation of reservoir behaviour

Investment decision for conversion of additional wells to injection wells

7 Conversion of additional injection wells

8-9 Evaluation of reservoir behaviour and requirement for additional wells

Conduct Concept and FEED studies for new facilities (if required) Environmental impact assessment, public hearings and approvals 10-11 Construction of pipeline

Construction and installation of wellhead platform Drilling of injection wells

12-35 Injection at nominal capacity

Continuous observation and seismic surveys every, say every 5 years 36 Decommissioning of surface facilities, plug and abandonment of wells Up to next

20 years Continuous observation of seabed and seismic surveys Transfer of responsibility

Release of financial security Table 0-4: Typical timeline for an offshore CO2 storage

Based on experience from other projects in terms of the permitting process, involvement of stakeholders and internal company approval to pass Final Investment Decision, the timeline presented here may seem shorter than what is realistic. But in view of the urgency of solving the climate problem and the need for reduction of CO2 content in the atmosphere, the timeline presented here is an estimation based on the assumption that the required political support will be available to realise it.

1.3.5 Sensitivity case – Reuse of existing offshore pipeline

According to the latest parliamentary agreement of 3 December 2020, the production of Danish oil & natural gas shall cease no later than 2050, and there may be an opportunity to utilise the Danish oil & gas pipeline grid or parts hereof for the transport of CO2 for underground storage. Assessing when which parts of the grid be-come available is outside the scope for this report, but at least one of the gas pipelines from the offshore fields to the Nybro gas terminal may become available earlier than 2050.

Unless CO2 is collected in a pipeline grid and sent to Nybro, this option will require that the CO2 is shipped to a nearby port where there should be an intermediate storage from which the CO2 is pumped through a new pipeline to Nybro and into e.g. the South Arne/Harald gas pipeline for injection into the Harald reservoir or other nearby reservoirs.

451 CO2 storage

The maximum operating pressure in the South Arne/Harald gas pipeline is limited to approx. 135 barg, which after pipeline losses most likely is insufficient injection pressure, for which reason a high-pressure injection pump must be installed offshore. But after the cease of gas production, there will be no fuel gas available for power generation, and therefore an alternative power supply must be installed. The cost of a power cable cannot be justified and installation of a new power module/platform with liquid-fired generator driver and associated fuel storage will both result in high investments and also a high operating cost.

As power source, it is therefore suggested to install two 100% rated wind turbines providing “free” electricity.

Fluctuation in the power available can be partly compensated for by controlling the export pressure from shore.

However, up to 5% of the time, there will be insufficient wind to operate the wind turbines. To compensate for this, additional intermediate storage capacity is required onshore. A conservative assumption is that a total intermediate storage capacity sufficient for one week of injection is required.

A generic 5 Mt/y case could be a 100,000 tonnes intermediate storage at a port in Jutland from where is pumped to Nybro through a 40 km pipeline and transferred to one of the offshore platforms. Here CO2 injection pumps are installed to inject the CO2 into the reservoir. In order to provide sufficient storage capacity, it is assumed that a new wellhead platform must be installed and connected by a new pipeline, say 30 km long. Power is provided from two new 4-6 MW offshore wind turbines – the smallest commercially available today.

Figure 0-27: 5 Mt/year offshore storage facility

Quantitative description

See separate Excel file for Data sheets of all cases. Input to the data sheets found below.