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 well data in well-explored areas also offer considerable insight into the nature of subsurface strata. However, since oil-producing areas in North America can be punctured by 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.
Multiple experiments run this year by Andrew Duguid reveal that cements commonly used for sealing oil and gas wells react quickly with CO2-rich fluids. In one experiment, rods of H-class cement were exposed to carbonated brines in a flow-through system at temperatures representing 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. In a second experiment, cement samples enclosed within porous limestone and sandstone and exposed to brines in batch reactors were not as quickly degraded, but permeability in reaction rings formed at the cement/stone interface increased by an order of magnitude in one month before leveling off. 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, an issue to be addressed by computer simulations of CO2 injection (see discussion below under “Numerical simulations of CO2 injection”).
Analysis of Field Samples
The impact of CO2 injection on well integrity also depends on whether cements in existing wells are more or less susceptible to attack than those used in the lab. This question is beginning to be answered by cements obtained from a 19 year-old well at the Rocky Mountain Oil Testing Center in Wyoming this September. 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.
Initial analysis of the samples by Mileva Radonjic has revealed a surprisingly complex microstructure that differs greatly from cements made in the lab. Further chemical analysis and strength testing will be carried out this winter, and a sample of the material will be exposed to the same carbonated brines used in previous experiments to test its durability.
Role of Microstructure in Cement Durability
One key difference that might account for the microstructural differences in lab and field cements is that the Wyoming cements were mixed with formation water containing sulfates. The team’s next step is to evaluate the importance of this difference by creating new samples for durability testing that mimic the original composition of recovered cements. These samples will be sent to a National Energy Technology Laboratory (NETL) laboratory in Pittsburgh for high-pressure curing to see if the unique microstructures of the Wyoming samples developed early in the cements’ history, or if they are the result of a longer-term process.
If the complex texture of the well cements can be reproduced, new durability studies will be carried out 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.