document preview

Abstract
The efficiency of Carbon Capture and Storage projects is directly related to the long term sealing ability of cemented sections in wellbores penetrating CO2 storage reservoirs. The microfractures inside the wellbore cement and/or microannulus are possible pathways for CO2 leakage to the surface and/or fresh water aquifers and jeopardize safe and long-term containment of CO2 in the subsurface.

This paper presents an experimental study which investigates the changes inside the cement internal structure when exposed to acidic brine through an artificial fracture. A 30-day long flow through experiment was conducted using a 1 in by 12 in. cement core and CO2 saturated brine, as a permeant, at a flow rate of 2 ml/min in a core flooding apparatus with10 psi and 600 psi of injection and net overburden pressures (Low Pressure-LP experiment). The same experiment was repeated with 1800 psi and 600 psi of injection and net overburden pressures for 10 days in order to account for the effects of pressure on the degradation process of cement (High Pressure-HP experiment). High-resolution X-ray computed tomography was used to image several subvolumes extracted from the flow-through cores. The images were processed and thresholded, followed by calculation of porosity. Total porosity was observed to decrease from 26% to 22% after 30 days of exposure of LP experiment. The HP experiment did not cause any significant change in total porosity possibly due to the short duration of the experiment.

Introduction
At the current state, Carbon Capture and Storage (CCS) technology offers a feasible solution to mitigate the problem of increasing atmospheric CO2. Risk assessment of a CO2 storage project requires an evaluation of the integrity of the wellbore network to be analyzed against the possible leakage scenarios over extended time scales (Bachu, 2009). An understanding about the behavior of microannulus or cement fractures under sequestration conditions is essential in order to analyze the integrity of existing wellbores and their extended service life under conditions for which they may not have been designed. Wellbore cement (pore fluid pH~13.5) will be in contact with acidic brine (pH ~3-5) in the post injection period, where the incompatibility arises from contact of two systems with widely different pH values. Hence, the cement behavior under dynamic CCS conditions needs to be investigated before implementing large scale projects. This was the main motivation for this experimental study.

Wellbore Cement
Oil and gas (O&G) wells are cased and cemented in order to provide zonal isolation, structural support for the wellbore and protection of casing against corrosive fluids such as CO2 and H2S rich brines. Maintenance of zonal isolation is the most important function of wellbore cement in CCS projects because it prevents both horizontal and vertical hydraulic conductivity within and into the wellbore. Nelson (2006) reports that some 11,000 casing strings in over 22,000 oil and gas wells in the Gulf of Mexico have been reported with sustained casing pressure which is an indication of inadequate zonal isolation. Most oil and gas wells are designed for 30-50 years of service life; however, CCS projects will require wellbore cements to maintain zonal isolation function for hundreds of years. The cause of wellbore leaking is frequently related to cement failure, which can be due to inadequate cement design or ineffective placement of cement (procedures, equipment, and technical inadequacy).