Oil and gas fields offer an appealing opportunity for storage, since their existence proves that a seal can keep hydrocarbons contained for millions of years. Seismic and borehole data in well-explored areas also offer considerable insight into the nature of subsurface strata. However, since oil-producing areas in North America have been punctured by many thousands of existing wells, the seal integrity of well cements is a critical factor in determining whether CO2 will stay stored, or leak up through these potential conduits to the surface.
Flow-through experiments of cement corrosion
George Scherer’s group is conducting laboratory experiments to study degradation of well cements under sequestration conditions. Interaction with low pH groundwater could lead to rapid dissolution of 20% of the material in cements, followed by structural collapse, but their behavior under sequestration conditions is not well known.
Because this cement project was a new undertaking initiated by CMI, much of the early years of the grant was spent setting up a laboratory and making initial analyses to characterize sample cements. Now flow-through experiments with a duration of one month and batch experiments with durations up to one year have been completed by Andrew Duguid, and the results show that cements commonly used for sealing oil and gas wells react quickly with CO2-rich fluids.
The flow-through experiments probe the maximum rate of attack under circumstances where fresh acid flows continuously over the cement. Rods of H-class cement were exposed to carbonated brines in a flow-through system at temperatures representing both surface and sequestration conditions. The samples showed complete loss of calcium hydroxide on a timescale of days, and outer layers were converted to a highly porous hydrous silica gel (Figure 6). The team’s results demonstrated that the cement is destroyed at a rate on the order of 0.1 mm/week under conditions comparable to sequestration in a sandstone formation at a depth of 1-2 km. This high rate of attack might be realized if a crack or annular gap allowed acidified brine to flow continuously over the cement in a well.
More likely rates of attack have been probed using batch experiments, in which the acid must diffuse through the pores of stone to reach the cement. Tubular samples of a representative sandstone and limestone were filled with relatively impermeable cement and exposed to brine solutions with varying temperatures and pH values for a year. At frequent intervals during the experiment, the group examined the rock-cement interface for physical and chemical changes that would affect cement permeability. The cement samples exposed to brines in the batch reactors were not as quickly degraded as those in the flow-through experiments, but in one month reaction rings formed at the cement/stone interface caused permeability to increase by an order of magnitude before subsequently leveling off.
In both types of experiments, the researchers found that the rate of attack was undetectably small when the brine was equilibrated with limestone prior to contact with the cement, because the acidity is reduced and the calcium content of the brine is increased by such exposure. These results imply that sequestration in limestone formations would be much less likely to result in cement corrosion than sequestration in sandstone formations.
The fast reaction times observed in the laboratory will pose a serious problem for carbon storage if cements are exposed to large volumes of fresh CO2-rich fluid in the subsurface. To determine whether such interaction is likely, data on the chemical profiles and spatial distribution of attack in the cements are being used to develop a computer model that will predict the composition of fluid in injection aquifers (see “Simulator development” below).
Scherer’s group has also recently established a collaboration with National Energy Technology Laboratory (NETL) laboratory in Pittsburgh to study cement corrosion under high-pressure conditions. The NETL study employs reaction vessels at 10-30 MPa, which are not available at Princeton and more closely approximate the environment in a storage formation. The NETL group’s initial results indicate that rates of cement corrosion decrease at elevated pressure, which would improve the outlook for carbon storage in deep saline aquifers. Work is ongoing both to quantify this pressure dependence and to identify the mechanism responsible.
Analysis of Field Samples
The actual impact of CO2 injection on well integrity depends on whether cements in existing wells are more or less susceptible to attack than those used in the laboratory. This question is beginning to be answered by cements obtained in 2004 from a 19 year-old well at the Rocky Mountain Oil Testing Center in Wyoming. George Scherer of the Storage group worked with Schlumberger and RMOTC staff to design and execute an innovative drilling project that retrieved one intact sidecore (composed of cement, casing, and formation rock) and several fragmented cement samples from depths of 3000-5000 feet (Figure 7).
Initial analysis of the samples by Mileva Radonjic revealed a surprisingly complex microstructure that differs greatly from cements made in the lab. One key factor that might account for the microstructural differences is that the Wyoming cements were mixed with formation water containing sulfates. However, initial preparation and high-pressure curing of a cement sample with the Wyoming “recipe” produced no unusual microstructure, which implies that the characteristics of the sample retrieved from the well are a consequence of long-term aging underground.
The group plans to submit the Wyoming cements to durability studies to see how the cements hold up to exposure to acidified brines. The work should provide insight into both the degradation potential of old well cements, and how to make new cements more resistant to attack.