Scottish Government

3| CO ₂ storage sites

To establish whether the Scottish offshore area has the potential for storing the amounts of CO ₂ captured, the study identified and assessed potential CO ₂ storage sites in the offshore area in terms of their relative storage capacities and geotechnical criteria.

Potential CO ₂ storage sites in the offshore area are:

• saline aquifers and;
• hydrocarbon fields.

Hydrocarbon fields have, by definition, the proven ability to trap migrating gas and oil in suitable 'reservoir' rock for many millions of years. Hydrocarbon fields that may be suitable for CO ₂ storage are

• those that either have ceased production, or will do so within the period covered by the study, or
• those that are suitable for enhanced oil recovery using CO ₂ (CO ₂- EOR).

Only a relatively small proportion of reservoirs contain hydrocarbon accumulations; the vast majority of potential reservoir rocks (typically sandstone in the North Sea) are filled with saline water, and these are known as saline aquifers.

Common to all types of storage site, the key metrics for assessing a potential site are:

• location;
• data availability;
• storage capacity;
• geotechnical characteristics of the storage site;
• timing of storage site availability.

3.1 Location

The area defined by the Scottish Renewable Energy Zone offshore has been examined (see map facing Contents page). It contains approximately 204 hydrocarbon fields (comprising 163 oil, 30 gas condensate and 11 gas fields) and 80 saline aquifers that might be suitable for the storage of CO ₂. These numbers may increase in future as further hydrocarbon fields or saline aquifers may yet be discovered.

3.2 Data availability

Eighty (40%) of the known hydrocarbon fields and twenty-one (26%) of known saline aquifers were not screened and assessed because of various issues such as lack of readily available data, confidentiality, time or budget (Figures 11 and 12). Many of these sites could be suitable for CO ₂ storage. Nevertheless, the storage sites remaining are considered to be representative of the whole area and include a large proportion of the potentially available capacity. Additional data from companies and government may well augment this list of potential storage sites as well as improve our understanding of those already identified.

3.3 Storage capacity and suitability

The CO ₂ storage capacity of a hydrocarbon field or saline aquifer depends upon several factors. The total volume of the storage reservoir is relatively straightforward to determine, provided appropriate data is available. At a microscopic scale, reservoir rocks (for example, sandstones) contain spaces (between sand grains) within which fluids can be stored, or through which fluids can pass (Figure 9). The proportion of the total volume available for fluids is its 'porosity', and the ease with which fluids can pass through rock is described by its 'permeability'.

Figure 9
Cartoon illustrating porosity and permeability within the reservoir volume.

These spaces are filled with either hydrocarbons (oil, gas or gas condensate) or saline water. These fluids are all pressurised to a certain degree and must be displaced to allow storage space for CO ₂. Thus, it is important to distinguish whether a reservoir is in 'open' pressure communication with surrounding rocks or whether it is 'closed'.

For oil fields not in pressure communication (closed), water is often injected to pressurise the reservoir and produce oil. Once production has ceased, much of the oil has been replaced by water but the reservoir may still be under high pressure. CO ₂ injection will cause further pressurisation. This places significant limits on the amount of CO ₂ that can be stored in this type of reservoir, since excessive pressure may ultimately cause fracturing of the caprock. The capacity available for CO ₂ can be increased by permitting further fluid production, either of additional oil or of the water previously injected which would require clean-up by extracting oil to meet current environmental standards prior to discharge to sea.

For gas and gas condensate fields the situation is different (even if closed) as production is usually driven by expansion of the gas without the need for water injection to maintain pressure. Thus pressure is likely to be very low by the time these fields become ready for CO ₂ storage.

For 'closed' saline aquifers pressure will again be the significant limiting factor. This was confirmed by numerical modelling carried out for this study and summarised later in this report (Section 5). Water production may be required to control pressure increase.

CO ₂ injected into 'open' reservoirs is accommodated by lateral displacement of the existing fluids, and gives rise to minimal, local changes in pressure. The storage capacity of 'open' saline aquifers is limited by how well the CO ₂ displaces the saline water (its 'sweep efficiency'), the proportion of the saline aquifer that is structurally closed (trapping the CO ₂) and the amount of CO ₂ retained during migration. Open reservoirs offer better potential for CO ₂ storage.

For the purpose of this strategic study, storage capacity was calculated at a basin-wide scale. This provides a ranking of potential storage sites but not absolute capacities. The best estimate of storage capacity of each reservoir will be refined as assessment becomes more focused (Figure 10).

Figure 10
Storage pyramid illustrating different stages in CO ₂ storage capacity assessment. This study takes the assessment to near the top of basin-scale.

For hydrocarbon fields, this basin-scale assessment enabled a ranking of their storage capacity. Following this analysis, the 95 hydrocarbon fields of estimated capacity less than 50 Mt CO ₂ were considered too small to be viable for CCS storage and so were not examined further (Figure 11). Note that stores with less than 50 Mt CO ₂ storage capacity may have value as satellites to larger sites or as part of a pilot or smaller scale demonstration project. Pressure-related issues further constrain the possibilities of using oilfield reservoirs for CCS.

The majority of oil fields in the Scottish offshore area are 'closed' and would require significant production of fluids (mainly previously injected water) to enable secure injection of significant quantities of CO ₂. This is unlikely to be practical except in combination with enhanced oil recovery (CO ₂- EOR). As part of this study, oil fields were assessed for their suitability for CO ₂- EOR and this is detailed in the next section entitled 'CO ₂-ENHANCED OIL RECOVERY' (Section 4).

The Brent Oil Field is a possible exception as pressure support has been withdrawn and water produced in order to drop the pressure and release the gas contained within the remaining oil. As a result, there may be a CO ₂ storage opportunity once depressurisation is complete and production has ceased (Table 4).

For gas and gas condensate fields, fewer limitations due to pressure in the reservoir are likely to be present. In all the gas condensate fields listed, there is minimal water replacement on production of hydrocarbons. Consequently, a large proportion of the pore space will be available for CO ₂ storage. However, three of the gas condensate fields, classified as High Pressure High Temperature ( HPHT) fields, are likely to be too costly to develop as CO ₂ stores. In the Frigg Gas Field, water is used to drive the gas and consequently a smaller proportion of the available pore space will be available for CO ₂ storage (Table 4).

Figure 11
Numerical breakdown of the 204 Hydrocarbon fields identified within the study area showing proportion of fields taken forward for assessment.

In summary, basin-scale analysis was used to identify 29 hydrocarbon fields with apparent potential for CO ₂ storage (Figure 11). Of these, four gas condensate fields (Brae North, Brae East, Britannia and Bruce fields), one gas field (the Frigg Field, UK) and one oil field (the Brent Field) present the most obvious opportunities as stores (Table 4) with total CO ₂ storage capacities of between 300 to 1000 Mt. The range of storage potential values reflects uncertainty with regard to assumptions in the calculation of storage capacity. The three HPHT gas condensate fields (Franklin, Elgin and Shearwater fields) are likely to be too expensive to develop as stores in the short term (Table 4). Fourteen oil fields, including the Brent Oil Field, have potential for CO ₂ storage in conjunction with Enhanced Oil Recovery (see following section 4). The remaining seven oil fields offer large storage capacities but reservoir pressure issues may present obstacles to their use for CO ₂ storage (Figure 13).

Table 4
Hydrocarbon fields assessed as having potential for CO ₂ storage alone.

Information about the properties of saline aquifers beneath the North Sea is less readily available than for hydrocarbons reservoirs. It was not feasible, within the constraints of this strategic assessment, to take into account the specific characteristics of individual saline aquifers. Instead, a generic figure for storage efficiency was derived from other regional studies and numerical modelling. Consequently, storage capacities for saline aquifers are given as ranges derived from storage efficiencies of 0.2% and 2% of pore volume (Table 6). Ten saline aquifers of storage capacity less than 50 Mt were excluded from detailed analysis (Figure 12).

3.4 Geotechnical characteristics of the storage site

Within the context of this strategic overview, geotechnical characteristics did not constitute immediate grounds for excluding any hydrocarbon fields since they have demonstrated that they are capable not merely of storing but of producing fluids. Nevertheless, these criteria have been flagged for each hydrocarbon field as this is useful information in any decision making process regarding suitability for CO ₂ storage (Table 4). This is not necessarily the case for saline aquifers which were further screened using best practice geotechnical criteria (Table 5) categorised as green, meeting best practice requirements and orange, meeting minimum technical requirements (Table 5). The injection of CO ₂ into a specific saline aquifer was investigated with the results detailed in the section entitled 'CO ₂ INJECTION MODELLING WITHIN SALINE AQUIFERS' (Section 5).

Thirty-nine saline aquifers were excluded from further consideration because they do not meet minimum geotechnical requirements (Figure 12). Ten saline aquifers have therefore been identified as meeting both geotechnical (best, green and minimum, orange) and storage capacity requirements (Table 6).

Table 5
Summary of geotechnical screening criteria applied to saline aquifers.

Figure 12
Numerical breakdown of the 80 saline aquifers identified within the study area showing proportion taken forward for assessment.

Table 6
Saline aquifers assessed as having potential for CO ₂ storage showing the range of potential storage capacities calculated from storage efficiencies derived from regional studies and numerical modelling.

3.5 Timing of storage site availability

As a practical working assumption, unless a hydrocarbon field is to undergo CO ₂- EOR storage, CO ₂ storage cannot begin until production ceases. Close of production (CoP) for all hydrocarbon fields was estimated from past production data (Table 4). For oil fields the CoP is of limited relevance, as use for storage without EOR is unlikely and CO ₂- EOR will necessarily begin prior to the estimated closure date. It has been assumed that there are no timing restrictions governing the availability of saline aquifers, although exploration and appraisal of saline aquifers may take a number of years. One of the most pertinent issues for the development of a CCS transportation pipeline involving hydrocarbon stores is the matching of timing of CO ₂ supply (from onshore sources) with available injection and storage capacity. Re-use of hydrocarbon production facilities may be an option in some cases. Historically, close of production forecast dates have tended to be unreliable, and depend on technology development, oil and gas prices, infrastructure lifetimes, and other market factors.

Oil & gas fields are currently better characterised in terms of both capacity and integrity than are saline aquifers so initially involve lower cost and risk. Without Enhanced Oil Recovery, oilfields offer limited capacity due to the past replacement of produced oil with water for pressure support. Depleted gas and gas condensate fields offer good storage capability, although there are relatively few in the Scottish Renewable Energy Zone. Storage of CO ₂ in the offshore Scottish Renewable Energy zone is likely to be initially in depleted gas and gas condensate fields and in the few oil fields where pressure conditions are favourable, whilst long-term storage and the majority of storage capacity potential is likely to be in saline aquifers.

All 29 hydrocarbon fields and ten saline aquifers identified in this study as having the potential to store CO ₂, either as part of an EOR project or purely as part of a CO ₂ mitigation strategy are shown in Figure 13. The ten saline aquifers are colour coded according to whether they meet minimum or best practice geotechnical requirements (Table 5). They each have a unique size and shape, and the majority cover areas of several thousand square km. In some places, the saline aquifers overlap each other, being present at different depths at the same geographical location. The circles in Figure 13 denote their approximate central points.

Figure 13
The location of all 29 hydrocarbon fields and 10 saline aquifers identified as potential CO ₂ storage sites within the Scottish offshore.

Risks and uncertainties are associated with all types of subsurface CO ₂ storage reservoir, but with appropriate, storage site specific, appraisal it should be possible to reduce these to the level appropriate for business investment in and regulatory approval of a project typical of the oil and gas industry. It is likely that appraisal costs to reach this position will be higher for saline aquifers than for oil and gas fields, although saline aquifer capacity for storage is also likely to be correspondingly greater.

CO ₂ storage sites-key conclusions

Basin-scale assessment has demonstrated

• From this first assessment, ten saline aquifers have been identified with a total CO ₂ storage capacity of between approximately 4,600 and 46,000 Mt, providing a capability to store at least 200 years of Scotland's CO ₂ output.
• Further study is necessary to fully scope saline aquifer storage potential.
• 29 hydrocarbon fields (21 oil, 7 gas condensate and one gas field) offer significant further CO ₂ storage potential. Amongst these:
• • 8 Gas and gas condensate fields offer the best potential for storage;
  • Three high pressure high temperature gas condensate fields are unlikely to be used as storage sites due to prohibitive costs;
  • Oil fields are unlikely to be employed as CO ₂ stores except in conjunction with Enhanced Oil Recovery;
  • The one remaining gas and four remaining gas condensate fields offer total ~ 700 Mt CO ₂ storage potential;
  • Unusually, the Brent Oil Field offers an opportunity for CO ₂ storage of ~ 400 Mt.
• The potential storage capacities as currently assessed are sufficient to provide an approximate ranking of sites in terms of their storage potential but sites need to be evaluated individually using more detailed models.