Capacity calculations and variation in storage

The storage capacity is a function of, among others, the area and thickness of the reservoir, pressure and po-rosity. Therefore, there is a need to have good seismic surveys and proper well data from the potential reser-voirs.

A regional or unconfined aquifer usually has a large area of hundreds or thousands of square kilometres. The storage capacity is a function of the hydraulic ability of the injected CO2 to saturate the porosity of the reservoir.

This is expressed by the storage efficiency.

Storage capacity in a regional aquifer:

Q = A · D · φ · ρCO

2 · h

st

where Q is the storage capacity in kg, A is the areal distribution of the aquifer (m²), D is the cumulative thickness of good reservoir rocks (m), φ is the effective porosity (<1), h

st is the storage efficiency (<1), and ρCO

2 is the density (kgm^-3) of CO

2 at reservoir conditions.

A confined reservoir is of more limited extent, for instance bounded by faults. When enclosed totally by barriers such as fault (or non-porous rocks), the storage will behave like a pressure tank and the storage capacity is a

451 CO2 storage

function of how much pressure the system can, or is allowed, to take. This approach is particularly useful in depleted oil and gas fields.

In a confined reservoir the storage capacity principally depends on constraining the pressure increase with respect to caprock stability, and can be written:

Source: Best Practice for the storage of CO2 in saline aquifers, BGS 2008

The injection capacity per well is one of the most important parameters for assessing costs of CO2 storage as the number of wells is the main cost driver. The injection capacity will depend on cap rock strength, reservoir characteristics, as well as geometry of the storage structure and the well design. Applying highly deviated or horizontal well sections in the storage reservoir increases injectivity and CO2 dispersion within the reservoir, which is favourable in particular for offshore developments where well costs are higher.

In the present study, it is estimated that injectivity per well will be in the range of about 0.5 million tonnes of CO2 per year in the Gassum Formation sandstone reservoirs, which comprise the majority of the potential stor-age sites mapped by GEUS. This assumption is assumed also to be valid for the depleted offshore sandstone oil and gas fields in question. The use of a well injection capacity is based on a general comparison with other, high-quality reservoirs. The Sleipner Utsira Formation comprises very permeable, shallow and unconsolidated sands with an average permeability of 2 Darcy, and the injector well could presumably take several million tonnes per year with ease. The Northern Light Johanssen Formation would fall in the range of 0.5-0.6 Darcy to locally beyond 1 Darcy, and the facility is designed to take 0.6 to 1.5 Mt pa presumably from one well. The most prevalent Danish sandstone formation in question, the Gassum Formation, is of good quality with permeabili-ties of up to about ½ a Darcy; thus we assume an injectivity rate of about 0.5 Mt pa, occasionally – in the case of the offshore oil field storage – up to 1 Mt pa during periods when CO2 is shipped in on a weekly basis. It should be noticed that the estimated 0.5 Mt pa per well is for the entire duration of the storage facility lifetime, i.e. 30 years. Experience from Canada where thousands of wells have been used for (acid) gas injection shows that the most common cause of well failure is loss of injectivity.

Use of CO2 for EOR, and incidental storage, is documented to be very efficient not only in sandstone reservoirs but also in carbonate reservoirs such as in the Sacroc and Weyburn oil fields. North Sea chalk reservoirs are generally of low permeability and high porosity, thus possessing a high theoretical storage capacity but with a low injectivity rate, requiring a high transmissivity in order to be suitable for CO2 injection. The transmissivity is the permeability multiplied by the length of the well in contact with the reservoir. Consequently, storage in chalk reservoirs would be of potential interest where existing long horizontal wells and other infrastructure such as wellhead platforms could be re-used. Studies on the potential for use of CO2 for EOR in chalk fields in

the Norwegian and Danish sectors have indicated considerable potential, which could also be interpreted to indicate suitability for geological storage of CO2.

As there will be a need for continuous maintenance and intervention into the injector wells, it is assumed that it would be prudent to have an extra well per storage site or storage complex. Additionally, in order to avoid excessive, local pressure build-up there is a need to distribute the CO2 within the storage structure, otherwise it may not be possible to utilise the entire storage volume. Exceeding the allowed reservoir pressure could lead to problems with the Competent Authority and thus with the storage permit. Typically, an offshore develop-ment for 1 Mt/year would hence require 3 wells while a developdevelop-ment for 3 Mt/year would require 7 wells.

However, these estimates are very site-specific, and after some years of operation of a storage facility it will be possible to reduce this uncertainty.

For onshore aquifers, there may be a further requirement for observation wells to ensure the integrity and compliance of the storage complex. The number of observation wells will depend on the size of the storage.

There may be a need for 2 to 6 observation wells at the spill points of the storage structure depending on the results of the seismic survey and the regulatory requirements. In the quantitative assessment, 2 wells have been assumed for a 1 Mt/y development, 4 wells for a 3 Mt/y development and 6 wells for a 5 Mt/y develop-ment.

Figure 0-8: Schematic illustration of a storage site with central injection wells and observation wells placed to monitor the flanks and the spill-point of the structure [9]

For offshore saline aquifers and depleted oil and gas fields, there may not be the same need for spill point observation wells as marine seismic will be readily available at more frequent intervals. In oil and gas fields, containment and cap rock integrity have been assured by geologic history, and in these cases it is assumed that observation well(s) would be converted, existing wells equipped with down-hole pressure sensors.

451 CO2 storage