No abstract

Integrated modeling of basin-and plume-scale processes induced by full-scale deployment of CO 2 storage was applied to the Mt. Simon aquifer in the Illinois Basin. A 3D mesh was generated with local refinement around 20 injection sites, with ~30 km spacing. A total annual injection rate of 100 Mt CO 2 over 50 years was employed. The CO 2 -brine flow at the plume scale and the single-phase flow at the basin scale were simulated. Simulation results show the overall shape of a CO 2 plume consisting of a typical gravity-override subplume in the bottom injection zone of high injectivity and a pyramid-shaped subplume in the overlying multilayered Mt. Simon, indicating the important role of a secondary seal with relatively low permeability and high entry capillary pressure. The secondary seal effect is manifested by retarded upward CO 2 migration as a result of multiple secondary seals, coupled with lateral preferential CO 2 viscous fingering through high-permeability layers. The plume width varies from 9.0 to 13.5 km at 200 years, indicating the slow CO 2 migration and no plume interference between storage sites. On the basin scale, pressure perturbations propagate quickly away from injection centers, interfere after less than a year, and eventually reach basin margins.The simulated pressure buildup of 35 bar in the injection area is not expected to affect caprock geomechanical integrity. Moderate pressure buildup is observed in Mt. Simon in northern Illinois. However, its impact on groundwater resources is less than the hydraulic drawdown induced by long-term extensive pumping from overlying freshwater aquifers.

The Shenhu Area is located in the Pearl River Mouth Basin, the northern continental slope of the South China Sea. In 2007, gas hydrate samples were recovered during the scientific expedition conducted by the China Geological Survey in the area. Using numerical simulation and currently available data from site measurements, including the water depth, thickness of the hydrate-bearing layer (HBL), sediment porosity, salinity, and pressures and temperatures at key locations, we developed preliminarily estimates of the production potential of these hydrates as gas-producing resource. We used measurements of ambient temperature in the sediments to determine the local geothermal gradient. Evidence from this and other field studies showed that the initial pressure distribution followed the hydrostatic gradient. Direct measurements from core samples provided estimates of the initial hydrate saturation and of the intrinsic permeabilities in the various strata of the system. The hydrate accumulations in the Shenhu Area appear to be hydrate deposits involving a single HBL within fine-textured sediments and boundaries (overburden and underburden layers) which have the same intrinsic permeabilities with the HBL. We investigated gas production from the Shenhu hydrates by means of depressurization and thermal stimulation using a single horizontal well placed in the middle of the HBL. The simulation results indicated that the hydrates dissociate along cylindrical interfaces around the well and along horizontal dissociation interfaces at the top and bottom of the HBL. Production is invariably lower than that attainable in a confined system, and thermal stimulation is shown to affect only a limited region around the well. The sensitivity analysis demonstrates the dependence of production on the level of depressurization, the initial hydrate saturation, the intrinsic permeability of the HBL, the temperature of the well, and the initial temperature of the HBL. A general observation is that gas production is low and is burdened with significant water production, making the hydrate accumulations at the Shenhu Area unattractive production targets with current technology.

Although significant hydrate deposits are known to exist in the Ulleung Basin of the Korean East Sea, their survey and evaluation as a possible energy resource has not yet been completed. However, it is possible to develop preliminary estimates of their production potential based on the limited data that are currently available. These include the elevation and thickness of the Hydrate-Bearing Layer (HBL), the water depth, and the water temperature at the sea floor. Based on this information, we developed estimates of the local geothermal gradient that bracket its true value. Reasonable estimates of the initial pressure distribution in the HBL can be obtained because it follows closely the hydrostatic. Other critical information needs include the hydrate saturation, and the intrinsic permeabilities of the system formations. These are treated as variables, and sensitivity analysis provides an estimate of their effect on production.Based on the geology of similar deposits, it is unlikely that Ulleung Basin accumulations belong to Class 1 (involving a HBL underlain by a mobile gas zone). If Class 4 (disperse, low saturation accumulations) deposits are involved, they are not likely to have production potential. The most likely scenarios include Class 2 (HBL underlain by a zone of mobile water) or Class 3 (involving only an HBL) accumulations.Assuming nearly impermeable confining boundaries, this numerical study indicates that large production rates (several MMSCFD) are attainable from both Class 2 and Class 3 deposits using conventional technology. The sensitivity analysis demonstrates the dependence of production on the well design, the production rate, the intrinsic permeability of the HBL, the initial pressure, temperature and hydrate saturation, as well as on the thickness of the water zone (Class 2). The study also demonstrates that the presence of confining boundaries is indispensable for the commercially viable production of gas from these deposits.

For purposes of geologic storage, CO2 would be injected into saline formations at supercritical temperature and pressure conditions, and would form a separate phase that is immiscible with the aqueous phase (brine). At typical subsurface temperature and pressure conditions, supercritical CO2 (scCO2) has lower density than the aqueous phase and would experience an upward buoyancy force. Accordingly, the CO2 is expected to accumulate beneath the caprock at the top of the permeable interval, and could escape from the storage formation wherever (sub-)vertical pathways are available, such as fractures or faults through the caprock, or improperly abandoned wells. Over time, an increasing fraction of CO2 may dissolve in the aqueous phase, and eventually some of the aqueous CO2 may react with rock minerals to form poorly soluble carbonates. Dissolution into the aqueous phase and eventual sequestration as carbonates are