Identification of Wells with High CO2-Leakage Potential in Mature Oil Fields Developed for CO2-Enhanced Oil Recovery

Abstract

Previous work, presented in SPE 106817, "Evaluation of the Potential for Gas and CO2 Leakage along Wellbores", described a method to predict the potential for wellbore leakage which primarily occurs in the shallow areas of a wellbore. The work presented here focuses on the potential for leakage to occur from the deep regions of a wellbore, particularly from viable oil reservoirs. The potential for wellbore leakage where CO2 enhanced oil recovery (EOR) or sequestration is or may be conducted is specifically investigated. The Alberta Energy Resources Conservation Board collects and maintains data regarding cement types used in primary cementing of casing strings, stimulation information and abandonment data. These data were used to determine the potential for deep wellbore leakage in the presence of CO2. This deep wellbore leakage potential is then coupled with shallow wellbore leakage potential to predict which wells may leak to other reservoirs, potable groundwater aquifers or to the atmosphere in a CO2 sequestration or EOR project. Cements with additives such as bentonite have been shown to be particularly susceptible to CO2 attack. Wells were screened for cement blends placed in the deeper sections of the wellbore during primary cementing. This information is useful in predicting if a wellbore will remain leak free if CO2 is placed in the reservoir and the wellbore is contacted. The stimulation method was evaluated to determine if injected CO2 may break through to existing wellbores prior to full reservoir sweep, thus decreasing the time that the wellbore could remain leak free. Stimulations such as hydraulic fracture, perforating and acidizing with pressure were deemed to increase the likelihood that wellbores would leak due to cement sheath cracking coupled with CO2 attack of cement and casing. The abandonment method was also evaluated. In Alberta the primary form of zonal abandonment utilizes a mechanical bridge plug capped with cement. The bridge plug material is expected to fail in the presence of CO2 due to CO2 attack on elastomers and cast iron. Two large field evaluations are presented as case studies. Introduction Several client studies have been conducted to date in Alberta, Canada, to determine factors which may affect wellbore leakage. The findings of these studies were presented previously (Bachu and Watson, 2006; Watson and Bachu, 2007). These papers, particularly SPE 106817, presented an analysis of the factors that affect the leakage potential in the shallow part of a well, and a decision-tree type model which enables ranking of a well's potential to leak based on factors determined in the client studies. The original ranking system generally focused on leaks from the shallower regions of the well (Figure 1). These leaks typically manifest themselves at surface as annular pressure (surface casing vent flow-SCVF, known also as sustained casing pressure) or soil gas migration. This ranking system did not take into account the potential for a native or injected fluid or gas to create or increase the potential for a well to leak.

A methodology to estimate maximum probable leakage along old wells in a geological sequestration operation

“…An area previously identified as a possible location for largescale CCS deployment, southwest of Edmonton, Alberta, Canada in the vicinity of the Pembina Oil Field (Michael et al, 2009;Watson and Bachu, 2008), is used as the hypothetical site for the CO 2 injection. The study area, known as the Wabamun Lake area in the Alberta basin, is 50 by 50 km in size and contains more than one thousand old wells.…”

Interaction between a fractured marl caprock and CO2-rich sulfate solution under supercritical CO2 conditions

“…As a result of changes during CO 2 injection due to the increase in pressure and in brine acidification, as CO 2 dissolves and generates carbonic acid, minerals dissolve and precipitate. These changes can create or reactivate leakage pathways through abandoned and injection wells (Celia et al, 2005;Watson and Bachu, 2008;Angeli et al, 2009;Huerta et al, 2011;Luquot et al, 2013), preexisting faults, fractures or microcracks in the caprock (Shukla et al, 2010), zones of high permeability (Deng et al, 2013) or through reactivation of faults (Angeli et al, 2009;Tongwa et al, 2013). The success of long-term CO 2 storage will ultimately depend on the caprock sealing capacity.…”

Self‐healing of cement fractures under dynamic flow of CO2‐rich brine

“…The long-term, safe, and effective storage requires the identification, investigation, and risk assessment of potential leakage pathways [Bachu and Watson, 2006;Bachu and Bennion, 2009;Bachu and Celia, 2013;Watson and Bachu, 2008]. Large numbers of depleted oil and gas wells exist in mature sedimentary basins, including the Alberta Basin in western Canada and the Permian Basin of West Texas in the United States [Bachu, 2003;Gasda et al, 2004].…”