Minimizing leakage and excess pressure buildup
The storage capacity of the Bjarmeland formation is assessed by obtaining optimized injection strategies while penalizing leakage and pressure buildup. This example demonstrates that pressure is an important aspect when designing injection strategies. Managing pressure buildup in the formation can be carried out through appropriate well placement as well as water production. More details of the following examples can be found in [1].

A possible injection set-up in the Bjarmeland formation (Barents Sea)

In this example, four large structural traps contain very high trapping capacities. We place one well in each of these traps in an attempt to exploit this capacity. As will be shown below, this placement of wells is not ideal in terms of pressure buildup. However we use it as a starting point here to highlight the issue of pressure buildup, and show how a different placement can improve the situation.

The initial injection rates are shown (left). These rates are as much as 75 times that which is used at the Sleipner storage site, which is located in the Utsira formation, North Sea. It is unlikely that a single well could be used to inject at such a high rate due to operational limitations, and as such, penalizing pressure buildup is an important factor in obtaining a practical optimal injection strategy.


Comparison of initial and optimized strategies


Initial rates

Simulation of the initial rates (unoptimized) reveals that it is not practical to exploit the full trapping capacity of these four large traps with only four wells. The pressure in the formation increases to more than 6 times that of the overburden pressure around the wells.


Leakage penalized only

Optimizing the injection rates while penalizing leakage suggests a strategy in which the pressure in the formation rises to almost 7 times the overburden pressure around the wells.


Leakage and Pressure penalized

Optimizing the injection rates while penalizing both leakage and pressure suggests a strategy in which the wells inject a very small amount (relative to the initial guess). The rates of these wells were restricted due to the low overburden pressure and thus low pressure limit (we used a pressure limit of 90% of the overburden pressure).

Comparion of initial and optimized rates when penalizing leakage only versus both leakage and pressure.


Pressure management strategy 1: well relocation

In order to maximize storage, we relocate the wells downslope from the traps. At deeper depths, the overburden pressure is higher, thus the pressure limit is less restrictive. The optimal injection rates are still limited due to pressure, as expected, however the rates have increased considerably. Note that the CO2 injected by Well 2 quickly migrates upslope and into the nearby structural trap, and the pressure buildup that occurs at the top of the trap is more restrictive on the injection rate than the pressure buildup immediately near the well. This demonstrates the importance of penalizing pressure in the entire formation, not just near the wells. Indeed, the pressure limit in the shallowest regions may very well dictate how high the rates can be without jeopardizing the integrity of the caprock.


Pressure management strategy 2: include water production wells

Another strategy to maximize storage is to manage the pressure through brine extraction. We test this out by placing two water producing wells in locations where the CO2 plume is unlikely to migrate towards (otherwise the production wells could become a leakage pathway for CO2). The production wells are operated at a bottom hole pressure of approximately 1 bar (for illustrative purposes only), which causes them to produce a total of approximately 290 million cubic meters of water during the CO2 injection period. This example shows that including water production results in higher optimized injection rates while still maintaining an acceptable pressure rise.



1. R. Allen, H. M. Nilsen, O. Andersen, and K.-A. Lie. On obtaining optimal well rates and placement for CO2 storage. ECMOR XV - 15th European Conference on the Mathematics of Oil Recovery, Amsterdam, Netherlands, 29 Aug-1 Sept, 2016. DOI: 10.3997/2214-4609.201601823

Published December 9, 2016