Risk Assessment for Future CO 2 Sequestration Projects

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"This paper is the first of a series that attempts to assess the possible health and safety risks associated with large scale CO2 sequestration in deep brine reservoirs. The approach is based on analysis of available data on the operational track record from CO2 transportation and injection associated with enhanced oil recovery (CO2 -EOR) in the US.

Some of these risks are based on the oil and gas industry and enhanced oil recovery - which is not the same thing as Carbon Capture and Sequestration for geologic storage. According to Stephen

Connolly, (Health and Safety Executive) “There is relatively little experience worldwide in managing the risks associated with CO2, compared with oil and gas.”

This information comes from -

Risk assessment for future CO2 Sequestration Projects

Based CO2 Enhanced Oil Recovery in the U.S

presented at the

9th International Conference on Greenhouse Gas Control Technologies

(GHGT-9), Washington, D.C., November 16-20, 2008

Ian J. Duncan, Jean-Philippe Nicot, Jong-Won Choi

"This paper is particularly concerned with identification of the main business risks facing a company engaged in geological sequestration. Such risks include: (1) the operational risks of capturing, compressing, transporting and injecting CO2 ; (2) the risk of blowouts or very rapid CO2 release from wells; (3) the risk that CO2 put into long term geologic storage will leak into shallow aquifers and contaminate potable water by lowering pH and increasing dissolved metals and other components; and (4) the risk that sequestered CO2 (and possibly associated methane gas) will leak into the atmosphere reversing the climate change benefits of sequestration and perhaps requiring repayment of CO2 sequestration credits."

“On the Free State pipeline, two leak incidents occurred soon after pressurizing the line and were caused by manufacturing imperfections in welds. Both these leaks were too small to be detected by the flow measurement imbalance. A landowner called the toll-free number on the pipeline signage to alert the control room of unusual white smog emerging from the ground where the pipeline was located on his property, triggering a response from Denbury’s Operations group. The third incident on the Tinsley 8” line, occurred when an excavator accidentally cut the line. Company personnel were onsite for immediate dispatch to isolate the system. On the Barksdale 6-3 #1 flowline incident (cement lined pipe rupture due to inadequate weld pre-heating), automatic shut-downs and alarms worked as designed. In the fifth incident at a pump station was minimal and observed by on-scene personnel. On the Free State pipeline, each leak caused minimal release but a controlled release of 75 MMCF (each) was required to depressurize the pipeline segment for repair.”

CO2well blowouts

The blowout of a well occurs when the operator of the well loses control of the pressure in the well resulting in fluid flow out of the well. Damen et al. [10] have suggested that the largest risk associated with CO2 injection for sequestration in deep brine reservoirs is well failure. Such failures result from a failure to adequately control pressures in the injection system. This is typically due to mechanical failure of a component or an external event directly affecting the well. This results in temporary loss of control of the process and the pressure of the reservoir drives CO2 and other entrained fluids upwards out of the well.

In most cases blowouts are caused by mechanical failures beyond human control, for example the failure of a back-flow preventer. This loss of containment immediately results in the pressure release vaporizing the supercritical CO2.In this context a blowout is driven by the high expansibility of the released gas resulting in a vigorous eruption of the vapor up the well bore (with the likely entrainment of particles of solid debris). If this occurs during drilling into a CO2 reservoir the rapidity of this phenomenon may make it a challenge to activate manual Blowout Prevention devices (BOPs) in time to prevent a blowout. Adiabatic cooling of CO2 during this rapid expansion leads to the gas being cooled below the freezing point (the triple point for CO2 being at -63°F and 76 psi). This results in the nucleation of dry ice and/or solid ice-like CO2-hydrates. These solids

can result in a blowout becoming a spray of solid particles. Such icy particles could damage pipes and other infrastructure in the path of the spraying particles. Whether this phenomenon is less risky than the CO2 irrupting as a fountain of dense CO2remains to be determined. If much of the CO2in a large blowout is in a frozen form then the risks posed by the initial blowout to the local are probably lowered.

Blowouts of oil production wells within CO2-EOR reservoirs are a known hazard (Lynch et al. [11]; Skinner [13]). In 2003,Skinner in a paper in “World Oil” focusing on blowouts in the CO2-EOR industry in the US suggested that there had been an “increased frequency of CO2 blowouts in injection projects.”

Read the full article - http://www.beg.utexas.edu/gccc/bookshelf/2008/GHGT9/08-03i-Final.pdf