Qualification and management of storage resources (2009-2013)

Qualification and management of storage resources (2009-2013)

Overall objective: The main objective was to develop procedures and tools to integrate data for qualification of prospective CO2 storage sites including development of modeling tools for pressure prediction during CO2 injection.

Contribution to one or more of the overall goals/objectives of BIGCCS

Following industry advice, BGS intend to attempt to better understand and quantify the stress field within the Southern North Sea (SNS).  Making use of the extensive well data available to BGS for this region, we plan to compare the break-out data from the Bunter Sandstone down through the Zechstein salt and into the Carboniferous bedrock.  It is postulated that the salt serves to decouple the overburden from the bedrock and the regional stress field may not apply in the Bunter Sandstone.

 Major achievements 

One of the activities – Large scale CO2 modeling with BGS in lead –  contributed to the objectives of BIGCCS by research related to large scale modeling of pressure development in potential CO2 storage sites by analyzing field data from the Southern North Sea, showing the relationship between the hydrostatic, lithostatic, leak off pressures (LOP) and modeled fault failure (reactivation) gradients. It is possible that LOP values falling between the various pressure gradients are influenced by the following factors: Tests not being fully taken to leak-off (a), reactivation of optimally oriented faults (b), reactivation of non-optimally oriented faults (c), failure of intact rock (d), or local variations of the lithostatic pressure gradient and spurious LOP measurements (e).

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Radial fractures can develop in sealing formations around the well bore if the cooling effect from the well stream is very strong.

All the flow modelling studies have followed the same injection strategy:

• 12 Injection wells and 2 Mt year per well injection rate

• 50 year injection period

The Bunter is assumed to have 100mD reservoir permeability in the following examples.  Initially, the injection is limited by the fracture pressure at the wells and 1196 Mt of CO2 can be injected. It is assumed that the full amount of 1200 Mt of CO2 could be injected if the initial injection rate was ramped-up rather than suddenly commencing at 2 Mt year per well as in these simulations (injection rate is controlled by bottom hole pressure at the injection wells, which is affected by a relative permeability-related pressure increase at the onset of injection).  Figure 5 shows the CO2 saturation and pressure change following injection.

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CO2 saturation (left) and pressure change (right) following injection of CO2 at 12 injection wells. Injection is limited by fracture pressure at well location.

 

In the updated basin modeling tool SEMI CO2 Demo version, cap rock leakage routines for CO2 within trap structures have now been included. This is illustrated in Figure below showing the migration traces from the plume to the trap filled with CO2.

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