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The perceived risk of CO2 leakage through wells has been considered a potential limitation to commercial scale deployment of geologic CO2 storage. However, chemical and mechanical alteration of cement can reduce the permeability of leakage pathways. We conducted 100s of simulations spanning realistic operating conditions and well-damage characteristics to understand (1) under what conditions and time frames do fractures seal and (2) for fractures that do not seal, how quickly and to what extent is the permeability reduced. For the conditions simulated, fractures with apertures in the tens of microns seal while those greater than hundreds of microns may exhibit long-term leakage. Fractures with apertures between 10 and 500 μm took a few days to a couple of years to seal. For non-sealing fractures mechanical deformation of altered asperities can rapidly reduce permeability. A sealing criterion was developed to relate fracture aperture with the cemented length required for self-sealing. Longer cemented intervals can seal large fractures; however, they take longer to seal and leak larger volumes before sealing. While the results presented here are subject to uncertainties, the manuscript provides a framework in which a model can be used to quantitatively answer questions regarding well integrity to facilitate decision making.

Reactive transport models can be used to predict the long-term storage capacity of CO2 in carbonate formations if the parameters that couple physical and chemical interactions can be calibrated from centimeters (laboratory-scale) to kilometers (field-scale). However, calibration across length scales is challenging in highly reactive and heterogeneous carbonate reservoirs. In this study we translated simulations of CO2-induced carbonate dissolution and transport processes of centimeter-sized cores to meter-sized rock blocks. The meter-sized rocks represent an intermediate scale between laboratory experiments and field demonstrations. We conducted brute-force, meter-sized simulations maintaining the same grid resolution used to successfully model rock heterogeneities and physical behaviors observed in laboratory experiments. To do this, we applied multi-point statistics to generate rock heterogeneity that honors characterization data, and adopted the reaction and transport parameters (e.g., reaction rate kinetics, porosity-permeability relationship) from models calibrated by core-flood experiments. We used the high-resolution simulation data sets to understand the interplay between carbonate reactivity, flow velocity, and rock heterogeneity on the development and consequences of dissolution fronts at a meter scale, and in particular how parameters that couple chemistry and transport change at variable length scales. The modeling results reveal scale dependence of porosity-permeability relationship and carbonate reactivity. We found that upscaling reactive transport processes from centimeters to meters requires: (1) Effective representation of initial rock heterogeneity and related preferential flow field. In more permeable rocks, several dissolution fingers or wormholes form and grow along the flow direction, competing for reactive solution and leading to fast breakthrough. In less permeable rocks, a single dissolution channel forms with a dramatic increase in lateral branching due to the resistance from low-permeability regions along the flow path. (2) Higher exponential values for porosity-permeability power-law correlations. The value of the power parameter n increases by about two times as we scale the dissolution process from centimeters to meters. (3) Lower carbonate reaction rates. Carbonate reaction rates obtained for meter-sized models are about ten times slower than those for the smaller core-flood experiments. We also used the high-resolution meter-sized simulations to upscale carbonate dissolution by coarsening the representative elementary volumes (or grids). The calibrated reactive transport parameters are consistent with those derived from scaling analysis. The upscaling analysis developed in this study improves our understanding of carbonate dissolution (especially wormhole development) and associated reactive transport across time and length scales, providing a useful basis for establishing a direct relationship between core-scale and field-scale models. Additional work is needed to see if relationships developed from single-phase reactive transport processes shown in this work are directly applicable to in-situ reservoir multiphase flow conditions arising from geological storage of CO2.

Understanding the performance of carbon dioxide (CO2) stored in geologic reservoirs requires some knowledge of the subsurface heterogeneity, where the most reliable data is extracted from wellbore measurements. This advantage is especially true for carbonate reservoirs were reactions between supercritical CO2, the reservoir brine, and carbonate minerals create new storage capacity and enhanced permeability. Techniques like NMR well logging hold promise for estimating subsurface permeability, because the total porosity and pore size can be calculated from response of 1H NMR signal. Resulting depth profiles of porosity and permeability from downhole logs are useful input for reservoir simulations and can be used to design injection protocols and estimate storage capacity. We conducted a detailed characterization study to quantify the NMR response to matrix pore space, the connectivity to larger vugs and fractures, and the resulting permeability of core samples from distinct carbonate formations. The cores used in study span 5 orders in permeability, 4 orders in mean T2, and 2%–42% in porosity. The goal of the study was to use independent measures of pore volumes, surface relaxivity, fluid-accessible surface areas, and permeability to develop carbonate permeability models. It was not possible to develop a single model that reproduced permeability for different carbonate formations, because phenomena specific to the reservoirs could not be extracted even with the state-of-the-art characterization techniques used in this study. Estimates of permeability require calibration. Best estimates for a given formation were achieved by using a simple form of the Kozeny equation (Eq. 6)

This article “goes local” to investigate the representation of women on city councils, seeking explanations for the variation in women’s descriptive representation at the municipal level. Using the State of New Jersey (NJ) as a case, it is asked: what explains why women fare electorally better in some NJ municipalities than in others? More specifically, what explains “blanks”—or councils on which women are absent—in women’s representation in local politics? It is demonstrated that council size is a significant predictor of women’s presence or absence, but not percentage representation, on city councils.

Maintaining well integrity is critical to the success of geologic carbon storage (GCS) and carbon dioxide enhanced oil recovery (CO2-EOR) operations. Wells that experience leakage because of integrity issues can potentially become a risk to the environment or human health if they release previously captured CO2 back into the atmosphere or into freshwater aquifers. There are many GCS and CO2-EOR sites in operation around the world. However, well integrity experiences at these sites are not widely documented in the public domain. This study details findings from a survey of well integrity experiences elicited from operators of GCS and CO2-EOR sites. The goal of the survey was to obtain information about site characteristics and operator experiences with well integrity, monitoring methods, and risk assessment of legacy wells. Literature relevant to the survey questions was also reviewed and summarized to provide context for survey responses and identify areas where field experiences with well integrity do and do not align with the current state of research. We highlight the current state-of-practice, identify research needs, and provide context for future interactions between researchers, operators, and regulators on issues related to well integrity.

Depleted oil reservoirs are considered a viable solution to the global challenge of CO2 storage. A key concern is whether the wells can be suitably sealed with cement to hinder the escape of CO2. Under reservoir conditions, CO2 is in its supercritical state, and the high pressures and temperatures involved make real-time microscopic observations of cement degradation experimentally challenging. Here, we present an in situ 3D dynamic X-ray micro computed tomography (μ-CT) study of well cement carbonation at realistic reservoir stress, pore-pressure, and temperature conditions. The high-resolution time-lapse 3D images allow monitoring the progress of reaction fronts in Portland cement, including density changes, sample deformation, and mineral precipitation and dissolution. By switching between flow and nonflow conditions of CO2-saturated water through cement, we were able to delineate regimes dominated by calcium carbonate precipitation and dissolution. For the first time, we demonstrate experimentally the impact of the flow history on CO2 leakage risk for cement plugging. In-situ μ-CT experiments combined with geochemical modeling provide unique insight into the interactions between CO2 and cement, potentially helping in assessing the risks of CO2 storage in geological reservoirs.

Depleted oil reservoirs are considered a viable solution to the global challenge of CO2 storage. A key concern is whether the wells can be suitably sealed with cement to hinder the escape of CO2. Under reservoir conditions, CO2 is in its supercritical state, and the high pressures and temperatures involved make real-time microscopic observations of cement degradation experimentally challenging. Here, we present an in situ 3D dynamic X-ray micro computed tomography (μ-CT) study of well cement carbonation at realistic reservoir stress, pore-pressure, and temperature conditions. The high-resolution time-lapse 3D images allow monitoring the progress of reaction fronts in Portland cement, including density changes, sample deformation, and mineral precipitation and dissolution. By switching between flow and nonflow conditions of CO2-saturated water through cement, we were able to delineate regimes dominated by calcium carbonate precipitation and dissolution. For the first time, we demonstrate experimentally the impact of the flow history on CO2 leakage risk for cement plugging. In-situ μ-CT experiments combined with geochemical modeling provide unique insight into the interactions between CO2 and cement, potentially helping in assessing the risks of CO2 storage in geological reservoirs. This is an open access article published under a Creative Commons Attribution (CC-BY) License, which permits unrestricted use, distribution and reproduction in any medium, provided the author and source are cited.

Wellbore integrity is a critical component of long-term carbon storage. Depleted reservoirs that are potential CO2 storage sites, typically contain several wells. Due to years of operations and abandonment, these wells can have cracks in the cement, cement-casing interface, and/or cement-formation interface. During CO2 injection, changes in temperature may result in stress variations that can further damage the well, threatening its integrity. The temperature difference between the cold injected CO2 and warm reservoir, and different thermal properties for the wellbore casing, cement, and the lithology, will stress the near wellbore environment, potentially extending pre-existing defects creating leakage pathways from the storage reservoir to the overlying strata. We have conducted a systematic numerical study to explore the role of CO2 injection temperature, downhole effective in-situ horizontal stress, and the thermo-mechanical properties by coupling a linear elastic stress model with heat conduction. We consider conditions in non-perforated casing above the injection zone where conductive heating is dominant. The injection temperatures considered covers current industrial practice as well as sub-zero temperatures. The latter represents direct injection following ship transport, without pre-heating. In this study, we consider the connection between damage risk and the temperature difference between the injected CO2 and the formation and downhole effective in-situ horizontal stress. The study found that the negative impacts of thermal stress in the wellbore environment are mitigated by the presence of effective in-situ horizontal stresses. Stresses normal to the well have the potential to reduce the tensile stress and stress intensity factor. In the absence of sufficient effective in-situ horizontal stress, thermal stress may cause the fracture to propagate due to high stress concentration near the fracture edges. In general, formations with large effective in-situ horizontal stress can prevent leakage paths from growing even when large temperature difference exists between the formation and the injected CO2. Our simulations suggest that CO2 can be injected at sub-zero temperatures, suitable for ship transport, when the downhole effective in-situ horizontal stress is greater than 10 or 12 MPa, depending on the location of the pre-existing cracks. For onshore transportation, injection of liquid CO2 results in minimal damage, provided there is ample in-situ horizontal stress.

Wellbore leakage tops the list of perceived risks to the long-term geologic storage of CO2, because wells provide a direct path between the CO2 storage reservoir and the atmosphere. In this paper, we have coupled a two-phase flow model with our original framework that combined models for reactive transport of carbonated brine, geochemistry of reacting cement, and geomechanics to predict the permeability evolution of cement fractures. This addition makes the framework suitable for field conditions in geological storage sites, permitting simulation of contact between cement and mixtures of brine and supercritical CO2. Due to lack of conclusive experimental data, we tried both linear and Corey relative permeability models to simulate flow of the two phases in cement fractures. The model also includes two options to account for the inconsistent experimental observations regarding cement reactivity with two-phase CO2-brine mixtures. One option assumes that the reactive surface area is independent of the brine saturation and the second option assumes that the reactive surface area is proportional to the brine saturation. We have applied the model to predict the extent of cement alteration, the conditions under which fractures seal, the time it takes to seal a fracture, and the leakage rates of CO2 and brine when damage zones in the wellbore are exposed to two-phase CO2-brine mixtures. Initial brine residence time and the initial fracture aperture are critical parameters that affect the fracture sealing behavior. We also evaluated the importance of the model assumptions regarding relative permeability and cement reactivity. Our results illustrate the need to understand how mixtures of carbon dioxide and brine flow through fractures and react with cement to make reasonable predictions regarding well integrity. For example, a reduction in the cement reactivity with two-phase CO2-brine mixture can not only significantly increase the sealing time for fractures but may also prevent fracture sealing.

Fractures along interfaces between host rock and wellbore cement have long been identified as potential CO2 leakage pathways from subsurface CO2 storage sites. As a consequence, cement alteration due to exposure to CO2 has been studied extensively to assess wellbore integrity. Previous studies have focused on the changes to either chemical or mechanical properties of cement upon exposure to CO2-enriched brine, but not on the effects of loading conditions. This paper aims to correct this deficit by considering the combined effects of the fracture pathway and changing effective stress on chemical and mechanical degradation at conditions relevant to geologic carbon storage. Flow-through experiments on fractured cores composed of cement and tight sandstone caprock halves were conducted to study the alteration of cement due to exposure to CO2-enriched brine at 3, 7, 9, and 12 MPa effective stress. We characterized relevant reactions via solution chemistry; fracture permeability via changes to differential pressure; mechanical changes via micro-hardness testing, and pore structure changes via x-ray tomography. This study showed that the nature and the rates of the chemical reactions between cement and CO2 were not affected by the effective stress. The differences in the permeability responses of the fractures were attributed to interactions among the geometry of the flow path, the porosity increase of the reacted cement, and the mechanical deformation of reacted asperities. The suite of observed chemical reactions contributed to change in cement mechanical properties. Compared to the unreacted cement, the average hardness of the amorphous silica and depleted layers was decreased while the hardness of the calcite layer was increased. Tomographic imaging showed that preferential flow paths formed in some of the core-flood experiments, which had a significant impact on the permeability response of the fractured samples. We interpreted the observed permeability responses in terms of competition between dissolution of cement phases (leading to enhanced permeability) and mechanical deformation of reacted regions (leading to reduced permeability).

The National Risk Assessment Partnership (NRAP) has developed a suite of tools to assess and manage risk at CO2 sequestration sites. The NRAP tool suite includes the Aquifer Impact Model (AIM), which evaluates the potential for groundwater impacts from leaks of CO2 and brine through abandoned wellbores. There are two aquifer reduced-order models (ROMs) included with the AIM tool, a confined alluvium aquifer, and an unconfined carbonate aquifer. The models accept aquifer parameters as a range of variable inputs so they may have broad applicability. The generic aquifer models may be used at the early stages of site selection, when site-specific data is not available. Guidelines have been developed for determining when the generic ROMs might be applicable to a new site. This paper considers the application of the AIM to predicting the impact of CO2 or brine leakage were it to occur at the Illinois Basin Decatur Project (IBDP). Results of the model sensitivity analysis can help guide characterization efforts; the hydraulic parameters and leakage source term magnitude are more sensitive than clay fraction or cation exchange capacity. Sand permeability was the only hydraulic parameter measured at the IBDP site. More information on the other hydraulic parameters could reduce uncertainty in risk estimates. Some non-adjustable parameters are significantly different for the ROM than for the observations at the IBDP site. The generic ROMs could be made more useful to a wider range of sites if the initial conditions and no-impact threshold values were adjustable parameters. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd.

Mineral reactivity can play an important role in fracture-controlled fluid networks where maintaining or increasing permeability is a goal, such as enhanced geothermal systems. In these systems, dissolution generates new void space, removes cement and physically transports less reactive mineral grains, while secondary precipitation acts to narrow or seal off fluid pathways. Sheet silicate mineral reactivity is likely to affect permeability evolution at the elevated temperatures of geothermal reservoirs because of the high reactive surface area and prevalence of these minerals in hydrothermal zones. To better describe the reactivity of one common sheet silicate, muscovite, we conducted kinetic dissolution experiments using flow-through reactors at temperatures of 100–280 °C and a pH range of 2–9. Surface area-normalized muscovite dissolution rates ranged from 0.17–155 · 10 − 11 mol m − 2 s − 1 over this temperature range, but showed little variation with pH above 150 °C. Aluminum was released to solution nonstoichiometrically with respect to dissolved silica, most likely resulting from secondary precipitation of an aluminum oxy-hydroxide identified as boehmite (γ-AlO(OH) (s) ) by X-ray diffraction in reaction products from experiments conducted at pH ≤ 6. Surface area-normalized muscovite dissolution rates, Rate mus (mol m − 2 s − 1 ), can be described from 25 to 280 °C with the following kinetic rate equation: R ate mus = 3 ∙ 10 − 3 ∙ e − 44 R ∙ T ∙ a H + 0.8 + 9 ∙ 10 − 6 ∙ e − 45 R ∙ T + 5 ∙ 10 − 1 ∙ e − 61 R ∙ T ∙ a OH − 0.6 ∙ 1 − e − ∆ G r RT where the rate and pre-exponential factors are in mol m − 2 s − 1 ; the activation energies, E , are in kJ mol − 1 ; a H + and a OH − represent the activities of H + and OH − , respectively; R (kJ mol − 1 K − 1 ) is the gas constant; T is the temperature in Kelvins; and Δ G r (kJ mol − 1 ) is a measure of how close the aqueous solution is to muscovite equilibrium. The rate equation is constrained by our new data literature rates and has been evaluated against previous formulations with varying dependence on reaction affinity. Although 150 °C muscovite rates from Oelkers et al. (2008) show a systematic dependence on reaction affinity, incorporating this dependence did not accurately reproduce the higher-temperature rates. We recommend the rate equation shown above, with an affinity term that slows reaction rates only when solutions are close to equilibrium, for simulating the dissolution of muscovite under geothermal conditions.

ConspectusWells are considered to be high-risk pathways for fluid leakage from geologic CO2 storage reservoirs, because breaches in this engineered system have the potential to connect the reservoir to groundwater resources and the atmosphere. Given these concerns, a few studies have assessed leakage risk by evaluating regulatory records, often self-reported, documenting leakage in gas fields. Leakage is thought to be governed largely by initial well-construction quality and the method of well abandonment. The geologic carbon storage community has raised further concerns because acidic fluids in the CO2 storage reservoir, alkaline cement meant to isolate the reservoir fluids from the overlying strata, and steel casings in wells are inherently reactive systems. This is of particular concern for storage of CO2 in depleted oil and gas reservoirs with numerous legacy wells engineered to variable standards.Research suggests that leakage risks are not as great as initially perceived because chemical and mechani...

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.

Contact between wellbore cement and carbonated brine produces reaction zones that alter the cement's chemical composition and its mechanical properties. The reaction zones have profound implications on the ability of wellbore cement to serve as a seal to prevent the flow of carbonated brine. Under certain circumstances, the reactions may cause resealing of leakage pathways within the cement or at cement-interfaces; either due to fracture closure in response to mechanical weakening or due to the precipitation of calcium carbonate within the fracture. In prior work, we showed how mechanical sealing can be simulated using a diffusion-controlled reaction-front model that links the growth of the cement reaction zones to the mechanical response of the fracture. Here, we describe how such models may be extended to account for the effects of the calcite reaction-rate. We discuss how the relative rates of reaction and diffusion within the cement affect the precipitation of calcium carbonate within narrow leakage pathways, and how such behavior relates to the formation of characteristic reaction modes in the direction of flow. In addition, we compare the relative impact of precipitation and mechanical deformation on fracture sealing for a range of flow conditions and fracture apertures. We conclude by considering how the prior leaching of calcium from cement may influence the sealing behavior of fractures, and the implication of prior leaching on the ability of laboratory tests to predict long-term sealing.

For this edition of Ask a Feminist, we turn to Susan J. Carroll—eminent political scientist and longtime advocate of women’s political participation—to address issues around gender and electoral politics. Her expertise and experience are needed now more than ever.

Beneficial pore space and permeability enhancements are likely to occur as CO2-charged fluids partially dissolve carbonate minerals in carbonate reservoir formations used for geologic CO2 storage. The ability to forecast the extent and impact of changes in porosity and permeability will aid geologic CO2 storage operations and lower uncertainty in estimates of long-term storage capacity. Our work is directed toward developing calibrated reactive transport models that more accurately capture the chemical impacts of CO2-fluid-rock interactions and their effects on porosity and permeability by matching pressure, fluid chemistry, and dissolution features that developed as a result of reaction with CO2-acidified brines at representative reservoir conditions. We present new results from experiments conducted on seven core samples from the Arbuckle Dolostone (near Wellington, Kansas, USA, recovered as part of the South-Central Kansas CO2 Demonstration). Cores were obtained from both target reservoir and lower-permeability baffle zones, and together these samples span over 3–4 orders of magnitude of permeability according to downhole measurements. Core samples were nondestructively imaged by X-ray computed tomography and the resulting characterization data were mapped onto a continuum domain to further develop a reactive transport model for a range of mineral and physical heterogeneity. We combine these new results with those from previous experimental studies (Smith et al., 2013; Hao et al., 2013) to more fully constrain the governing equations used in reactive transport models to better estimate the transition of enhanced oil recovery operations to long-term geology CO2 storage. Calcite and dolomite kinetic rate constants (mol m−2 s−1) derived by fitting the results from core-flood experiments range from kcalcite,25C = 10−6.8 to 10−4.6, and kdolomite,25C = 10−7.5 to 10−5.3. The power law-based porosity-permeability relationship is sensitive to the overall pore space heterogeneity of each core. Stable dissolution fronts observed in the more homogeneous dolostones could be accurately simulated using an exponential value of n = 3. Unstable dissolution fronts consisting of preferential flowpaths could be simulated using an exponential value of n = 3 for heterogeneous dolostones, and larger values (n = 6–8) for heterogeneous limestones.

The perceived risk of CO

Two of the most important challenges facing the global energy sector are to reduce the CO2 intensity and the water intensity of energy production. Because many economies will continue to depend on fossil fuels as primary energy sources, CO2 capture and storage (CCS) must play a major role in curbing CO2 emissions. A large portion of CO2 storage will need to occur in saline reservoirs because these resources are more widely distributed than hydrocarbon resources—where CO2 capture utilization and storage (CCUS) can be deployed for enhanced oil recovery (EOR). CCS deployment can be accelerated with a pressure-management strategy, called pre-injection brine production that proactively manages project risks linked to reservoir pressure. In this approach, a CCS wellfield is deployed sequentially, one well at a time, with each well being used for three stages: (1) monitoring, (2) brine production, and (3) CO2 injection. Using the same well to produce brine before injecting CO2 provides pre-injection reservoir diagnostics needed for proactive planning of wellfield operations. Because pressure drawdown is greatest where CO2 injection will subsequently occur, reservoir pressure is efficiently managed per well, and per unit of removed brine. This approach to managing geologic CO2 storage can (1) identify resources with sufficient CO2 storage capacity and permanence, and provide information needed to effectively manage those resources prior to injecting CO2; (2) increase CO2 storage capacity and efficiency; (3) limit pore-space competition with neighboring subsurface operations; and (4) reduce the duration of post-injection site care and monitoring, while (5) creating the opportunity to generate water, using an emerging CCUS technology called enhanced water recovery (EWR). Although beneficial consumptive use of produced brine may be preferred in water-constrained regions, there may be situations where the brine composition is not economically treatable, which could necessitate reinjecting some or all of the produced brine into a separate reservoir. In this study we consider a range of brine-disposition options, from 100% reinjection in the subsurface to near zero net injection of fluid, which maximizes the water generation benefit per tonne of stored CO2. These options are analyzed for a case where a nearby saline reservoir overlying a CO2 storage reservoir is used to store some or all of the brine removed from the CO2 storage reservoir.

This research responds to the call by early childhood educators advocating for more challenging mathematics curriculum at the primary level. The kindergarten Project M2units focus on challenging geometry and measurement concepts by positioning students as practicing mathematicians. The research reported herein highlights the features of the kindergarten units and reports on student achievement, including the differences between the intervention and comparison groups. Hierarchical linear modeling results indicate that students in the intervention group ( n = 210) outperformed those in the comparison group ( n = 196) on the Iowa Tests of Basic Skills Mathematics subscale ( p < .01; d = 0.25), and an open-response assessment ( p < .001; d = 2.68) encompassing performance-based, verbal, and written components. These results suggest that kindergarteners can achieve at high levels of mathematical understanding when given the opportunity to learn from more challenging curriculum.