Appendix 1 Methodology for estimating geological CO2 storage capacity

The assessments of geological CO2 storage capacities in this report conform as far as is possible to the methodology recommended by the CSLF (Bradshaw et al. 2007, Bachu et al. 2007).

Geological CO2 storage capacity can be considered in the same terms as any other resource: parts of it are well known - there is relative certainty about the existence and magnitude of this fraction. On the other hand, other (larger) parts of the resource are much more speculative and poorly quantified. It can be helpful to consider the CO2 storage potential of India, Pakistan, Bangladesh and Sri Lanka as a resource pyramid, which has a very wide base consisting of speculative potential, and an apex consisting of well-quantified and relatively certain capacity (Bradshaw et al. 2007). The theoretical CO2 storage capacity is represented by the entire pyramid and comprises the entire resource. A large part of it, visible at the base of the resource pyramid consists of speculative, poor quality and poorly quantified or unquantified potential. The effective storage capacity is capacity which meets a range of basic geological and engineering criteria and which can be quantified with a fair degree of confidence. It comprises all the capacity excluding the speculative, poor quality or poorly quantified potential. The practical capacity is a subset of the effective storage capacity that consists of potential storage sites that meet additional criteria and can be considered in terms of the annual CO2 storage rates that they might accommodate. Finally, at the apex of the pyramid, is matched storage capacity; a subset of the practical capacity that is obtained by detailed matching of large stationary CO2 sources with geological storage sites that are adequate in terms of capacity, injectivity and supply rate.

Figure A1.1. CO2 storage capacity resource pyramid (after Bachu et al. 2007)

Bachu et al. (2007) affirm that country-scale assessments of CO2 storage capacity should be performed to determine whether there is sufficient storage capacity in a country, what type or types of storage capacity are available and what challenges (or risks) may exist, without necessarily quantifying that country’s potential. This is because the recommended CSLF methodology for quantifying storage capacity relies on the availability of a large geological dataset for each potential storage medium (i.e. oil and gad gas fields, coal fields and saline aquifers). For India, Pakistan and Bangladesh, much of the necessary data is not in the public domain and so a fully quantitative estimate of their CO2 storage capacities could not be made. However, a qualitative comparison of the storage capacity with that of the European sector is given in Appendix 4. This employs the same methodology as used in the IEAGHG European sector study (Wildenborg et al. 2006).

Many approximations and assumptions have had to be made in the analysis. These are described in more detail in the text of the report. Therefore the estimates given in the report should be revised when more accurate data becomes available. The estimates presented represent the views of the authors and not necessarily those of the IEAGHG R&D programme, DEFRA or the countries concerned.



Following Bachu et al. (2007) the underlying assumption made in the estimates of the CO2 storage capacity of oil and gas fields is that the volume previously occupied by the produced hydrocarbons is available for CO2 storage. This assumption is generally valid for pressure-depleted reservoirs that are not in hydrodynamic contact with an aquifer, or that are not flooded during secondary and tertiary oil recovery. In reservoirs that are in hydrodynamic contact with an underlying aquifer, or are purposefully water-flooded during secondary production, formation water or injected water invades the reservoir as the pressure declines because of production, leading to a decrease in the pore space available for CO2 storage. CO2 injection can partially reverse any water influx, thus making more pore space available for CO2. However, not all the previously hydrocarbon-saturated pore space will become available for CO2 because some of the invading water will be trapped in the pore space due to capillarity, viscous fingering and gravity effects (Stevens et al., 2001).

Another important assumption is that CO2 will be injected into depleted oil and gas reservoirs until the reservoir pressure is brought back to the initial (virgin) reservoir pressure. In some cases reservoir depletion could damage the integrity of the reservoir and/or caprock, in which case it might not be possible to inject until the initial reservoir pressure is reached and the capacity would be lower. In other cases the pressure could be raised beyond the original reservoir pressure as long as it remains safely below the lesser of the capillary entry pressure and the threshold rock-fracturing pressure of the seal (caprock), in which case the CO2 storage capacity would be higher due to CO2 compression. However, raising the storage pressure to or beyond the original reservoir pressure requires a case-by-case reservoir analysis that is not practical for basin-scale evaluations.

Finally, in many cases the structure that hosts a hydrocarbon reservoir is not filled with oil and/or gas to the spill point. In such cases, the additional pore space down to the spill point might also be used for CO2 storage, but, to achieve this, the pressure would have to be increased beyond the original reservoir pressure, as discussed previously. In the time available for this study, it was not possible to determine which of the oil and gas fields were filled to spill point, so it was assumed that they were all full to spill point before production started.

Storage capacity calculations

There is no published information at all about many of the oil and gas fields in India. The CO2 storage capacity of these fields could not be estimated individually. State-by-state reserves figures are available in India but the reserves quoted are remaining reserves rather than remaining plus recovered reserves.

For many other fields only the ultimately recoverable reserves (URR) of oil and gas are publicly available. In order to estimate the pore space occupied by the URR, several assumptions had to be made. These are listed below:

  • Unless field-specific information is available, it is assumed that all gas produced from fields with oil production is dissolved gas, the reservoir volume of which can be accounted for by applying a formation volume factor (FVF). This will likely result in an underestimate of CO2 storage capacity because some of the fields likely have gas caps, and this pore space will not be accounted for in the calculations.
  • The formation volume factor applied to all oil fields is 1.2 unless there is field-specific information available.
  • Where the initial reservoir temperature and pressure are not known, the density of CO2 under reservoir conditions is assumed to be 600 kg m-3.

Using these assumptions, the pore space occupied by the ultimately recoverable reserves in an oil field is estimated as follows:

MCO2 = (VOIL (stp).Bo) . ρCO2 (Equation 1)


MCO2 = CO2 storage capacity

stp = standard temperature and pressure

VOIL (stp) = volume of ultimately recoverable oil at stp

Bo = oil formation volume factor (the ratio between a volume of oil and the dissolved gas that it contains at reservoir temperature and pressure and the volume of the oil alone at stp)

ρCO2 = density of CO2 at reservoir conditions (kg m-3)

The pore space occupied by the ultimately recoverable reserves in a gas field is calculated as follows:

MCO2 = (VGAS (stp) / Bg) . ρCO2 (Equation 2)


MCO2 = CO2 storage capacity (106 tonnes)

Stp = standard temperature and pressure

VGAS (stp) = volume of ultimately recoverable gas at stp (109 m3)

Bg = gas expansion factor (from reservoir conditions to stp)

ρCO2 = density of CO2 at reservoir conditions (kg m-3)

The pore space occupied by the URR was then discounted by 35% to allow for water invasion into the reservoir and/or water injection into oilfields for secondary recovery.



The methodology used to estimate the CO2 storage capacity of India was:

  1. Estimate the mass of coal that might be available for CO2 storage in each coal field.
  2. Estimate the average mass of CO2 that might be stored per tonne of coal, using an absorption coefficient and a saturation coefficient.
  3. Multiply the above to derive the potential CO2 storage capacity.

All the important factors in the above method involve a degree of judgement. The estimate the mass of coal that might be available for CO2 storage in each coal field was based on expert judgement by one of the authors. The estimate of the average mass of CO2 that might be stored per tonne of coal is based on an arbitrary assumption that the average sorption capacity if in situ Indian coal available for CO2 storage is 16.6 standard m3 CO2/tonne raw untreated coal and 60% saturation of the available sorption sites can be achieved (the latter following the rule of thumb proposed by Bromhal et al. 2003). On this basis approximately 10 standard m3 CO2/tonne coal (approximately 0.02 tonnes CO2/tonne coal) can be stored. It was assumed that all coal available for CO2 storage is of sufficient permeability. At greater depths the sorption capacity may be greater but the achievable saturation is likely to be lower because of the reduced permeability.

No account was taken of the ECBM potential of Indian coal as this is not known for all coalfields.


Bradshaw. J., Bachu, S., Bonijoly, D., Burruss, R., Holloway, S., Christensen, N-P. Mathiasen, O-M.2007. CO2 storage capacity estimation: Issues and development of standards. International Journal of Greenhouse Gas Control, 1(1), 62-68.

Bachu, S., Bonijoly, D., Bradshaw, J., Burruss, R., Holloway, S., Christensen, N-P. & Mathiassen, O-M. 2007. CO2 storage capacity estimation: Methodology and gaps. International Journal of Greenhouse Gas Control, 1(4), 430-443.

Bromhal, G.S., Sams, N.W., Jikich, S., Ertekin, T. & Smith, D.H. 2005. Simulation of CO2 sequestration in coal beds: The effects of sorption isotherms. Chemical Geology 217(3-4): 201-211.

Stevens, S.H., Kuuskraa, V.A. & Gale, J. 2001. Sequestration of CO2 in Depleted oil and Gas Fields: Global Capacity, Costs and Barriers. Proceedings of 5th International Conference on Greenhouse Gas Control Technologies, (ed. D. Williams B. Durie, P. McMullan, C. Paulson & A.Smith), Collingwood, Australia: CSIRO, pp. 278-283.

Wildenborg, A., Gale, J., Hendriks, C., Holloway, S., Brandsma, R., Kreft, E. & Lokhorst, A. 2006. Cost Curves for CO2 storage, European Sector. In: Rubin, E.S., Keith, D.W. & Gilboy, C.F. (eds.), Proceedings of 7th International Conference on Greenhouse Gas Control Technologies. Volume 1: Peer-Reviewed Papers and Plenary Presentations, Elsevier, p. 603-610.