Permeability Decline by Clay Fines Migration around a Low-Salinity Fluid Injection Well.

Migration of clay fines can be a concern when less saline fluids are injected into brine-saturated sandstone formations containing clays. If the salinity near fluid injection wells decreases below a critical value, the clay fines near the injection may detach, start migrating, and finally clog the pores. This effect can cause permeability decline near the well and may rapidly reduce the well injectivity. The focus of this work is on evaluating the impacts of clay fines migration on permeability decline in the field, using a numerical model and pressure buildup data collected during successive variable-rate water injections in a deep sandstone reservoir. The numerical model accounts for the mixing of low-salinity water with native brine and the migration of clay fines with the detachment and pore-clogging processes. The model interpretation of the pressure buildup data implies that the observed reduction in well injectivity is mainly associated with the clay fines migration and related pore clogging near the well. The model reasonably well represents the pressure buildup data during the injections. Our simulations demonstrate that the permeability near the well can rapidly decline within the first hour of injection. The measured pressure buildup in post-injection periods appears to decay more rapidly, compared to the simulation results of the model that assume irreversible permeability damage. This raises the question whether the permeability damage may be partly reversible near the well by backflow of brine after the injection of low-salinity water.

Adsorption and Capillary Condensation-Induced Imbibition in Nanoporous Media.

Multiphase flow phenomena in nanoporous media are encountered in many science and engineering applications. Shales, for example, possessing complex nanopore networks, have considerable importance as source rocks for unconventional oil and gas production and as low-permeability seals for geologic carbon sequestration or nuclear waste disposal. This study presents a theoretical investigation of the processes controlling adsorption, capillary condensation, and imbibition in such nanoporous media, with a particular focus on understanding the effects of fluid-fluid and fluid-pore wall interaction forces in the interconnected nanopore space. Building on a new theoretical framework, we developed a numerical model for the multiphase nanoporous flow and tested it against water vapor uptake measurements conducted on a shale core sample. The model, which is based on the density functional approach, explicitly includes the relevant interaction forces among fluids and solids while allowing for a continuum representation of the porous medium. The experimental data include gravimetrically measured mass changes in an initially dry core sample exposed to varying levels of relative humidity, starting with a low relative humidity (rh = 0.31) followed by a period of a higher relative humidity (rh = 0.81). During this process, water vapor uptake in the dry core is recorded as a function of time. Our model suggests that, under low rh conditions, the flow within the shale sample is controlled by adsorption- and diffusion-type processes. After increasing the rh to 0.81, the uptake of water vapor becomes more significant, and according to our model, this can be explained by capillary condensation followed by immiscible displacement in the core sample. It appears that strong fluid-pore wall attractive forces cause condensation near the inlet, which then induces water imbibition further into sample.

Identifying chemicals of concern in hydraulic fracturing fluids used for oil production.

Chemical additives used for hydraulic fracturing and matrix acidizing of oil reservoirs were reviewed and priority chemicals of concern needing further environmental risk assessment, treatment demonstration, or evaluation of occupational hazards were identified. We evaluated chemical additives used for well stimulation in California, the third largest oil producing state in the USA, by the mass and frequency of use, as well as toxicity. The most frequently used chemical additives in oil development were gelling agents, cross-linkers, breakers, clay control agents, iron and scale control agents, corrosion inhibitors, biocides, and various impurities and product stabilizers used as part of commercial mixtures. Hydrochloric and hydrofluoric acids, used for matrix acidizing and other purposes, were reported infrequently. A large number and mass of solvents and surface active agents were used, including quaternary ammonia compounds (QACs) and nonionic surfactants. Acute toxicity was evaluated and many chemicals with low hazard to mammals were identified as potentially hazardous to aquatic environments. Based on an analysis of quantities used, toxicity, and lack of adequate hazard evaluation, QACs, biocides, and corrosion inhibitors were identified as priority chemicals of concern that deserve further investigation.

Multiphase modeling of geologic carbon sequestration in saline aquifers.

Geologic carbon sequestration (GCS) is being considered as a climate change mitigation option in many future energy scenarios. Mathematical modeling is routinely used to predict subsurface CO2 and resident brine migration for the design of injection operations, to demonstrate the permanence of CO2 storage, and to show that other subsurface resources will not be degraded. Many processes impact the migration of CO2 and brine, including multiphase flow dynamics, geochemistry, and geomechanics, along with the spatial distribution of parameters such as porosity and permeability. In this article, we review a set of multiphase modeling approaches with different levels of conceptual complexity that have been used to model GCS. Model complexity ranges from coupled multiprocess models to simplified vertical equilibrium (VE) models and macroscopic invasion percolation models. The goal of this article is to give a framework of conceptual model complexity, and to show the types of modeling approaches that have been used to address specific GCS questions. Application of the modeling approaches is shown using five ongoing or proposed CO2 injection sites. For the selected sites, the majority of GCS models follow a simplified multiphase approach, especially for questions related to injection and local-scale heterogeneity. Coupled multiprocess models are only applied in one case where geomechanics have a strong impact on the flow. Owing to their computational efficiency, VE models tend to be applied at large scales. A macroscopic invasion percolation approach was used to predict the CO2 migration at one site to examine details of CO2 migration under the caprock.

Radionuclide transport behavior in a generic geological radioactive waste repository.

We performed numerical simulations of groundwater flow and radionuclide transport to study the influence of several factors, including the ambient hydraulic gradient, groundwater pressure anomalies, and the properties of the excavation damaged zone (EDZ), on the prevailing transport mechanism (i.e., advection or molecular diffusion) in a generic nuclear waste repository within a clay-rich geological formation. By comparing simulation results, we show that the EDZ plays a major role as a preferential flowpath for radionuclide transport. When the EDZ is not taken into account, transport is dominated by molecular diffusion in almost the totality of the simulated domain, and transport velocity is about 40% slower. Modeling results also show that a reduction in hydraulic gradient leads to a greater predominance of diffusive transport, slowing down radionuclide transport by about 30% with respect to a scenario assuming a unit gradient. In addition, inward flow caused by negative pressure anomalies in the clay-rich formation further reduces transport velocity, enhancing the ability of the geological barrier to contain the radioactive waste. On the other hand, local high gradients associated with positive pressure anomalies can speed up radionuclide transport with respect to steady-state flow systems having the same regional hydraulic gradients. Transport behavior was also found to be sensitive to both geometrical and hydrogeological parameters of the EDZ. Results from this work can provide useful knowledge toward correctly assessing the post-closure safety of a geological disposal system.

Effect of dissolved CO2 on a shallow groundwater system: a controlled release field experiment.

Capturing carbon dioxide (CO(2)) emissions from industrial sources and injecting the emissions deep underground in geologic formations is one method being considered to control CO(2) concentrations in the atmosphere. Sequestering CO(2) underground has its own set of environmental risks, including the potential migration of CO(2) out of the storage reservoir and resulting acidification and release of trace constituents in shallow groundwater. A field study involving the controlled release of groundwater containing dissolved CO(2) was initiated to investigate potential groundwater impacts. Dissolution of CO(2) in the groundwater resulted in a sustained and easily detected decrease of ~3 pH units. Several trace constituents, including As and Pb, remained below their respective detections limits and/or at background levels. Other constituents (Ba, Ca, Cr, Sr, Mg, Mn, and Fe) displayed a pulse response, consisting of an initial increase in concentration followed by either a return to background levels or slightly greater than background. This suggests a fast-release mechanism (desorption, exchange, and/or fast dissolution of small finite amounts of metals) concomitant in some cases with a slower release potentially involving different solid phases or mechanisms. Inorganic constituents regulated by the U.S. Environmental Protection Agency remained below their respective maximum contaminant levels throughout the experiment.

Monitoring CO2 intrusion and associated geochemical transformations in a shallow groundwater system using complex electrical methods.

The risk of CO(2) leakage from a properly permitted deep geologic storage facility is expected to be very low. However, if leakage occurs it could potentially impact potable groundwater quality. Dissolved CO(2) in groundwater decreases pH, which can mobilize naturally occurring trace metals commonly contained in aquifer sediments. Observing such processes requires adequate monitoring strategies. Here, we use laboratory and field experiments to explore the sensitivity of time-lapse complex resistivity responses for remotely monitoring dissolved CO(2) distribution and geochemical transformations that may impact groundwater quality. Results show that electrical resistivity and phase responses correlate well with dissolved CO(2) injection processes. Specifically, resistivity initially decreases due to increase of bicarbonate and dissolved species. As pH continues to decrease, the resistivity rebounds toward initial conditions due to the transition of bicarbonate into nondissociated carbonic acid, which reduces the total concentration of dissociated species and thus the water conductivity. An electrical phase decrease is also observed, which is interpreted to be driven by the decrease of surface charge density as well as potential mineral dissolution and ion exchange. Both laboratory and field experiments demonstrate the potential of field complex resistivity method for remotely monitoring changes in groundwater quality due to CO(2) leakage.

Pressure buildup and brine migration during CO2 storage in multilayered aquifers.

Carbon dioxide injection into deep saline formations may induce large-scale pressure increases and migration of native fluid. Local high-conductivity features, such as improperly abandoned wells or conductive faults, could act as conduits for focused leakage of brine into shallow groundwater resources. Pressurized brine can also be pushed into overlying/underlying formations because of diffuse leakage through low-permeability aquitards, which occur over large areas and may allow for effective pressure bleed-off in the storage reservoirs. This study presents the application of a recently developed analytical solution for pressure buildup and leakage rates in a multilayered aquifer-aquitard system with focused and diffuse brine leakage. The accuracy of this single-phase analytical solution for estimating far-field flow processes is verified by comparison with a numerical simulation study that considers the details of two-phase flow. We then present several example applications for a hypothetical CO2 injection scenario (without consideration of two-phase flow) to demonstrate that the new solution is an efficient tool for analyzing regional pressure buildup in a multilayered system, as well as for gaining insights into the leakage processes of flow through aquitards, leaky wells, and/or leaky faults. This solution may be particularly useful when a large number of calculations needs to be performed, that is, for uncertainty quantification, for parameter estimation, or for the optimization of pressure-management schemes.

Modeling basin- and plume-scale processes of CO2 storage for full-scale deployment.

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 three-dimensional mesh was generated with local refinement around 20 injection sites, with approximately 30 km spacing. A total annual injection rate of 100 Mt CO(2) over 50 years was used. 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 1 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.

A temperature-profile method for estimating flow in geologic heat pipes.

Above-boiling temperature conditions, as encountered, for example, in geothermal reservoirs and in geologic repositories for the storage of heat-producing radioactive wastes, may induce strong liquid and gas flow processes in porous subsurface environments. The magnitude of these flow processes is extremely hard to measure in the field. We therefore propose a simple temperature-profile method that uses high-resolution temperature data for deriving such information. The energy that is transmitted with the vapor and water flow creates a nearly isothermal zone maintained at about the boiling temperature, referred to as a heat pipe. Characteristic features of measured temperature profiles, such as the differences in the gradients inside and outside of the heat-pipe regions, are used to derive the approximate magnitude of the liquid and gas fluxes in the subsurface.