3.8 CO2 storage

As the 2009 study showed, the economics of CO2 storage is dependent upon the geology of the target formation. The geology will drive the storage site selection and the site will drive the commerciality of commercial scale, integrated CCS projects. In this update, the “finding” costs applied are assumed to range from US$25 million in the ideal case to US$150 million or more depending on the geology. This is consistent with the 2009 study.

Given the high variability of geologic properties within a region, let alone across nations, the assumption was made that the ‘reservoir’ properties were identical across all the jurisdictions for which recent market costs were available (North America, Europe and Australia/New Zealand). This allowed for a direct comparison of potential storage costs over these regions and an understanding of what the key capital and operating costs are for each region. It was also assumed that all storage projects occur onshore, an assumption that avoids the highly variable costs of drilling offshore. A further assumption is that no EOR is possible as a means of revenue offsets for CO2 storage. Thus, the storage scenarios allow for ‘reasonable’ comparisons. In cases where storage costs for CO2 were not available, the costs of hydrocarbons exploration programs were used as analogues.

Furthermore, in order to treat the inherent uncertainty of storage, two case study scenarios were considered. The two cases were for a ‘good’ reservoir and a ‘poorer’ reservoir with either 3Mtpa or 12Mtpa injection scenarios modeled. These are presented in Table 3-6. In this case, the primary differences between the two reservoirs are the absolute permeability and the reservoir thickness.

Table 3-6 Geological and well properties for ‘poorer reservoir’ and ‘good reservoir’

Units ‘Poor reservoir’ ‘Good reservoir’
Net thickness m 5.0 15.0
Absolute permeability md 150 400
Reservoir mid-depth m 1700 1700
Initial pore gradient bar/m 0.1002 0.1002
Temperature gradient C/100m 3.0 3.0
Surface temperature C 20 20
Fracture gradient bar/m 0.136 0.136
Initial pore pressure bar 170 170
Reservoir temperature C 71 71
Injection pressure limit (of FG) 90% 90%
Initial injection pressure bar 208 208
Relative permeability 0.3 0.3
Drainage radius m 762 762
Wellbore radius m 0.09 0.09
Total skin 2.5 2.5

For both these cases, the well counts at the start of the injection period and end of the injection period were calculated using a number of factors to control well count. It was assumed that no heating of the CO2 was required upon delivery to the injection site (this may be a simplification which would require both power and compressors at the wellhead thus increasing capital (CAPEX) and operations and maintenance (OPEX) costs) and that the injection pressure was always maintained at 90 per cent of the fracture gradient thus reducing operational risk from injection induced fracturing. The drainage radius assumes that the CO2 forms a circular pool (‘pancake’) at the injection point (that is, that the reservoir is wholly homogenous throughout all the injection points).

The analysis assumed that a suitable reservoir was located and characterised and that injection could commence once the capture plant was online. It was also assumed that the exploration and appraisal program that would start in late 2010 to prove up these sites (and others as a potential portfolio of storage options) was successful and that the locations would have been shown to have suitable seals and other geological factors that would allow for safe storage of CO2 over the longer term. Thus, the analysis assumes that the developmental timeline for the storage site starts at the FEED phase to allow injection to commence from 2016 onwards. In both cases, ‘finding costs’ are included in the site selection and. Vertical injection wells are used in both cases as the standard. The evaluation did not consider stimulation by fracturing or deviated well placement that could increase injection rates. Such well design considerations would be considered after the site characterisation and the full field development program are complete.

This analysis required that the injection well pressure was below the fracture pressure (90 per cent of fracture pressure) which provides the first order constraint on potential storage volumes. CO2 injection above the fracture pressure could increase well injectivity rates, but at the risk of fracturing the cap-rock. Thus, an accurate determination of the actual fracture pressure can only be derived from laboratory tests on new core samples from both areas. Another assumption is that sufficient pore space is available over the life of the injection operations.

This analysis required that the injection well pressure was below the fracture pressure (90 per cent of fracture pressure) which provides the first order constraint on potential storage volumes. CO2 injection above the fracture pressure could increase well injectivity rates, but at the risk of fracturing the cap-rock. Thus, an accurate determination of the actual fracture pressure can only be derived from laboratory tests on new core samples from both areas. Another assumption is that sufficient pore space is available over the life of the injection operations.

As previously discussed in the 2009 Foundation Report Two, the key factor determining the cost of CO2 storage is the ‘reservoir permeability thickness product’ (k·h) since this determines the injectivity of the site and thus controls the well count needed for a given volume of CO2.

As can be seen in Table 3-7 below, the final well counts required for each reservoir for both injection scenarios are as follows.

Periodically new wells will need to be brought online in the poor reservoir to allow for the constant injection volume to be maintained on an annual basis. This is due to the ‘back pressure’ exerted by the reservoir as it fills with CO2, meaning that the original injection volume on the initial injector wells will decrease over time, thus necessitating new wells for constant volumetric injection.

Table 3-7 Well counts for ‘Poor reservoir’ and ‘Good reservoir’

Reservoir quality injection volume 3Mtpa 12Mtpa
‘Poor reservoir’ 16 61
‘Good reservoir’ 2 8

Regional cost comparison

Recent data on the costs for CO2 storage were available from Australia/New Zealand, Europe, and North America for CO2 injection wells and associated services. These are listed in Table 3-8. Whilst proprietary data was available for China, confidentiality issues prevented the release of this information. As a result, Australia and New Zealand (ANZ) was used as a proxy for this region.

Table 3-8 Regional costs for CO2 storage

Regional Costs (in 2010 US$) ANZ Europe US
3D Seismic survey mln US$/svy 18 25 18
Deep monitoring well costs mln US$/well 6 6 5
Shallow monitoring well costs mln US$/well 0.50 0.70 1
Injection well costs mln US$/well 7 7 10
Injection well abandonment costs & rehab mln US$/well 1 0.70 1
Monitoring well abandonment costs & rehab mln US$/well 0.50 0.70 0.5
In-field flow lines mln US$/well 0.24 0.35 0.25
Drilling cost escalation per annum % 7 % 5 % 5 %
Well-related OPEX % of DrillEX 5 % 5 % 5 %
Monitoring OPEX mln $/yr 0.10 0.14 0.10
Fees & Rents OPEX mln $/yr 0.10 0.14 0.10

There is little headline difference in the well costs between each of the regions. This recognises that the costs estimates for the complete study is in the order of +/- 40 per cent and indeed the similarity of the costs can be taken as an indication that the market for well services/rigs is worldwide. Thus, companies will seek to move staff and assets to areas of demand.