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In this study we correlate monitoring thresholds and chemical changes in underground sources of drinking water chemistry from the leakage of storage reservoir fluids using synthetic data. The geologic scenario is based on geology and legacy well locations near Kimberlina California, USA. The modeled scenario is an ideal site for potential CO2 storage in many respects because the legacy well is significantly far from the injection location, and the simulated leakage produces modest volumes of impacted groundwater. We assess the sensitivity of magnetotellurics (MT) to changes in groundwater chemistry as a function of depth and plume volume. The results show the importance of monitoring all permeable units to increase the likelihood of detecting and mitigating a leak as soon as possible, rather than monitoring only above the cap rock. Sensitive methods would be needed to detect the modest plumes that were simulated based on the Kimberlina geology, however MT could be used to detect more aggressive leaks with much higher TDS changes and larger volumes.

We present an approach for managing geologic CO2 storage using wells that serve three sequential purposes (1) characterization and monitoring, (2) brine production, and (3) CO2 injection. Two reservoirs are deployed in tandem: (1) a CO2-storage reservoir and (2) a brine-storage reservoir. This approach provides data that can be analyzed prior to CO2 injection, enabling proactive reservoir management, which reduces cost and risk. We analyze a range of brine-disposition options, including 100% reinjection in a nearby brine-storage reservoir and cases where a portion of the produced brine is used to generate water, with the residual brine reinjected in the nearby reservoir. We also consider the option of time-shifting the parasitic load of brine production and injection, so that those operations can utilize excess energy from electric grids during periods of over-generation.

A comprehensive risk-based monitoring assessment methodology is developed to (i) incorporate background data for thresholds and monitoring design, (ii) use stochastic leakage simulations and monitoring modeling for risk scenarios given uncertainty, (iii) apply statistical methods to combine multiple monitoring techniques and provide decision support for evaluating proposed monitoring plans, and (iv) facilitate implementation in the National Risk Assessment Partnership (NRAP) integrated assessment model (IAM) framework. This methodology is illustrated using a case representative of the High Plains aquifer, considering the stochastic leakage events simulated using reactive transport simulations. The resulting groundwater quality changes were reflected in three groundwater monitoring parameters (pH, TDS and benzene concentrations), which were used to calculate the corresponding detection probability for each simulation, based on the background distributions and the selected thresholds. The consequent detection probability was then used to evaluate the monitoring well density and the proposed network designs. Beyond the detectability, the earliest response time and spatial coverage constraints of a monitoring network design are considered, and the role of adaptive monitoring strategies for compliance monitoring and incorporation of expert judgment on likely leakage locations is considered.

Wellbore integrity is critical to long term carbon storage. During CO2 injection, changes in temperature may result in large stress variations that can damage the well, threatening its integrity. The different materials comprising the wellbore and near-wellbore environment (namely the casing, cement and surrounding rock) possess different thermal properties. Consequently, there can be considerable variations in both material properties and thermal gradients across these layers, resulting in different amounts of contraction and expansion of these materials. This may generate sufficient thermal stresses to lead to fracture within the cement and/or host rock, or delamination of the cement/casing or cement/rock interfaces. Downsized wellbore samples have been used in laboratory studies to investigate the failure modes and failure criteria during thermal cycling operations. However, it is not clear to what extent such results can be reliably used to predict well failure at field scale conditions. In this work, we conduct a parameter study involving the size and material properties of the wellbore samples subjected to different rates of thermal loading, with the objective of predicting how these parameters can affect the thermal stress in field scale well conditions. A state-of-the-art parallel multiscale, multiphysics code named GEOS, developed at Lawrence Livermore National Laboratory, was used to study the thermal response of wellbore materials. A finite element solver considering linear elastic materials was coupled with a finite volume heat equation solver to simulate the wellbore deformation and fracture during thermal cycling. To understand the effect of wellbore size on thermal fracturing, simulations were conducted at different height to diameter ratios. The wellbore sample size was systematically varied from the lab scale to field scale with several intermediate scales. The change in thermal stresses were compared for different scales. Additionally, the effect of elastic modulus and cooling rates were studied.

The use of nuclear magnetic resonance (NMR) well log data has the potential to provide in-situ porosity, pore size distributions, and permeability of target carbonate CO 2 storage reservoirs. However, these methods which have been successfully applied to sandstones have yet to be completely validated for carbonate reservoirs. Here, we have taken an approach to validate NMR measurements of carbonate rock cores with independent measurements of permeability and pore surface area to volume (S/V) distributions using differential pressure measurements and micro X-ray computed tomography (μXRCT) imaging methods, respectively. We observe that using standard methods for determining permeability from NMR data incorrectly predicts these values by orders of magnitude. However, we do observe promise that NMR measurements provide reasonable estimates of pore S/V distributions, and with further independent measurements of the carbonate rock properties that universally applicable relationships between NMR measured properties may be developed for in-situ well logging applications of carbonate reservoirs.

Risk assessment for geologic CO2 storage including quantification of risks is an area of active investigation. The National Risk Assessment Partnership (NRAP) is a US-Department of Energy (US-DOE) effort focused on developing a defensible, science-based methodology and platform for quantifying risk profiles at geologic CO2 sequestration sites. NRAP has been developing a methodology that centers round development of an integrated assessment model (IAM) using system modeling approach to quantify risks and risk profiles. The IAM has been used to calculate risk profiles with a few key potential impacts due to potential CO2 and brine leakage. The simulation results are also used to determine long-term storage security relationships and compare the long-term storage effectiveness to IPCC storage permanence goal. Additionally, we also demonstrate application of IAM for uncertainty quantification in order to determine parameters to which the uncertainty in model results is most sensitive.

It is important to determine the geochemical reactions between common cements used in wellbore construction, formation mineralogy, and supercritical CO 2 stored in deep saline reservoirs, because abandoned and completed wells provide a pathway for release of the stored CO 2 back to overlying aquifers and to the atmosphere. Although it is known that alkaline cements readily react with acidic CO 2 -rich waters, the influence of the formation and cement mineralogy on the bonding of the wellbore cement to the caprock at pressure and temperature conditions associated with saline CO 2 storage reservoirs is uncertain. We reacted end member components of the heterolithic sandstone and shale unit that forms the upper section of the carbon storage reservoir at the Krechba Field, In Salah, Algeria with supercritical CO 2 and class G cement in a representative brine at 95 °C and 10 MPa in gold bag autoclaves to identify geochemical reactions that occur in the wellbore environment. The experimental system allows reaction progress of complex geochemical environments to be tracked by sampling the aqueous phase periodically over the two-month long experiments. Analysis of the solution chemistry over time and the solid products show that the wellbore environment is dominated by reactions between cement, carbonate, and clay minerals when exposed to CO 2 -rich fluid. Reaction of the hydrated cement with synthetic brine equilibrated with supercritical CO 2 rapidly forms amorphous silica, calcite, and aragonite. Similar reaction products were observed when cement reacted with sandstone and CO 2 (reservoir). However in the vicinity of the shale (caprock) cement minerals altered to calcium carbonate minerals and smectite (clay).

Carbon storage in deep saline reservoirs has the potential to lower the amount of CO 2 emitted to the atmosphere and to mitigate global warming. Leakage back to the atmosphere through abandoned wells and along faults would reduce the efficiency of carbon storage, possibly leading to health and ecological hazards at the ground surface, and possibly impacting water quality of near-surface dilute aquifers. We use static equilibrium and reactive transport simulations to test the hypothesis that perturbations in water chemistry associated with a CO 2 gas leak into dilute groundwater are important measures for the potential release of CO 2 to the atmosphere. Simulation parameters are constrained by groundwater chemistry, flow, and lithology from the High Plains aquifer. The High Plains aquifer is used to represent a typical sedimentary aquifer overlying a deep CO 2 storage reservoir. Specifically, we address the relationships between CO 2 flux, groundwater flow, and detection time and distance. The CO 2 flux ranges from 103 to 2×106 t/yr to assess chemical perturbations resulting from relatively small leaks that may compromise long-term storage, water quality, and surface ecology, and larger leaks characteristic of short-term well failure. Reactive transport simulations show the CO 2 leakage into a dilute groundwater creates a slightly acid plume that can be detected at some distance from the leak source due to groundwater flow and CO 2 buoyancy. pH breakthrough curves demonstrate that CO 2 leaks can be easily detected for CO 2 flux 104 t/yr within a 15-month time period. Sustained pumping in a developed aquifer mixes the CO 2 -affected water with the ambient water and enhances pH signal for small leaks (103 t/yr) and reduces pH signal for larger leaks (104t/yr). Detection of CO 2 leaks in aquifers by changes in pH and carbonate chemistry is readily available and well understood. Leaks produce a measurable change in pH that is still within range of natural waters, even for high flux rates (2×106 t/yr). Reactive transport modeling is a critical component to the design and effective performance of measurement, monitoring, and verification plans for carbon storage.

Reactive experiments were performed to expose sample cores from the Arbuckle carbonate reservoir to CO 2 -acidified brine under reservoir temperature and pressure conditions. The samples consisted of dolomite with varying quantities of calcite and silica/chert. The timescales of monitored pressure decline across each sample (and concurrent increases in permeability) in response to CO 2 exposure, as well as the amount of and nature of dissolution features, varied widely among these three experiments. For all samples cores, the experimentally measured initial permeability was at least one order of magnitude or more lower than the values estimated from downhole methods. Nondestructive X-ray computed tomography (XRCT) imaging revealed dissolution features including “wormholes,” removal of fracture-filling crystals, and widening of pre-existing pore spaces. In the injection zone sample, multiple fractures may have contributed to the high initial permeability of this core and restricted the distribution of CO 2 -induced mineral dissolution. In contrast, the pre-existing porosity of the baffle zone sample was much lower and less connected, leading to a lower initial permeability and contributing to the development of a single dissolution channel. While calcite may make up only a small percentage of the overall sample composition, its location and the effects of its dissolution have an outsized effect on permeability responses to CO 2 exposure. The XRCT data presented here are informative for building the model domain for numerical simulations of these experiments but require calibration by higher resolution means to confidently evaluate different porosity-permeability relationships.

A reactive transport modeling approach was used to assess key geochemical reactions between wellbore cement, formation mineralogy, and injected supercritical CO 2 at the Krechba natural gas field at In Salah, Algeria. Characterization of these reactions is important for understanding changes in porosity and permeability and the propagation or sealing of fractures in the formation or wellbore cement. Experiments involving the reaction of CO 2 with reservoir mineral assemblages and wellbore cement under in situ conditions, combined with geochemical modeling, were used to identify candidate reactive mineral phases and reaction rates specifically applicable to CO 2 injection at In Salah. These findings informed a reactive transport model which considered advective transport of CO 2 along the wellbore-formation interface and diffusive transport of CO 2 and brine constituents into juxtaposed wellbore cement. Model results indicate shallow carbonation of the cement along the interface, leading to changes in cement porosity. Diffusive transport of cations such as Ca, Fe, and Al between the cement and formation materials results in mineralogical changes in the formation material immediately adjacent to the cement, including localized dissolution of calcite and precipitation of siderite, magnesite, gibbsite, smectite, and amorphous silica. In contrast to the cement, the modeled porosity changes in the formation material appear to be minor. Taken together, these results suggest (1) significant retardation of the rate of advance of CO 2 along the interface, and (2) relatively minor impacts to permeability.

A careful assessment of the risk associated with geologic CO2 storage is critical to the deployment of large-scale storage projects. A potential risk is the deterioration of groundwater quality caused by the leakage of CO2 and brine leakage from deep subsurface reservoirs. In probabilistic risk assessment studies, numerical modeling is the primary tool employed to assess risk. However, the application of traditional numerical models to fully evaluate the impact of CO2 leakage on groundwater can be computationally complex, demanding large processing times and resources, and involving large uncertainties. As an alternative, reduced order models (ROMs) can be used as highly efficient surrogates for the complex process-based numerical models. In this study, we represent the complex hydrogeological and geochemical conditions in a heterogeneous aquifer and subsequent risk by developing and using two separate ROMs. The first ROM is derived from a model that accounts for the heterogeneous flow and transport conditions in the presence of complex leakage functions for CO2 and brine. The second ROM is obtained from models that feature similar, but simplified flow and transport conditions, and allow for a more complex representation of all relevant geochemical reactions. To quantify possible impacts to groundwater aquifers, the basic risk metric is taken as the aquifer volume in which the water quality of the aquifer may be affected by an underlying CO2 storage project. The integration of the two ROMs provides an estimate of the impacted aquifer volume taking into account uncertainties in flow, transport and chemical conditions. These two ROMs can be linked in a comprehensive system level model for quantitative risk assessment of the deep storage reservoir, wellbore leakage, and shallow aquifer impacts to assess the collective risk of CO2 storage projects.