Experimental evaluation of wellbore integrity along the cement-rock boundary

Carbonation Reaction Mechanisms of Portlandite Predicted from Enhanced Ab Initio Molecular Dynamics Simulations

Geological carbon capture and sequestration (CCS) is a promising technology for curbing the global warming crisis by reduction of the overall carbon footprint. Degradation of cement wellbore casings due to carbonation reactions in the underground CO2 storage environment is one of the central issues in assessing the long-term success of the CCS operations. However, the complexity of hydrated cement coupled with extreme subsurface environmental conditions makes it difficult to understand the carbonation reaction mechanisms leading to the loss of well integrity. In this work, we use biased ab initio molecular dynamics (AIMD) simulations to explore the reactivity of supercritical CO2 with the basal and edge surfaces of a model hydrated cement phase—portlandite—in dry scCO2 and water-rich conditions. Our simulations show that in dry scCO2 conditions, the undercoordinated edge surfaces of portlandite experience a fast barrierless reaction with CO2, while the fully hydroxylated basal surfaces suppress the formation of carbonate ions, resulting in a higher reactivity barrier. We deduce that the rate-limiting step in scCO2 conditions is the formation of the surface carbonate barrier which controls the diffusion of CO2 through the layer. The presence of water hinders direct interaction of CO2 with portlandite as H2O molecules form well-structured surface layers. In the water-rich environment, CO2 undergoes a concerted reaction with H2O and surface hydroxyl groups to form bicarbonate complexes. We relate the variation of the free-energy barriers in the formation of the bicarbonate complexes to the structure of the water layer at the interface which is, in turn, dictated by the surface chemistry and the degree of nanoconfinement.

A Critical Review of the Physicochemical Impacts of Water Chemistry on Shale in Hydraulic Fracturing Systems

Hydraulic fracturing of unconventional hydrocarbon resources involves the sequential injection of a high-pressure, particle-laden fluid with varying pH's to make commercial production viable in low permeability rocks. This process both requires and produces extraordinary volumes of water. The water used for hydraulic fracturing is typically fresh, whereas "flowback" water is typically saline with a variety of additives which complicate safe disposal. As production operations continue to expand, there is an increasing interest in treating and reusing this high-salinity produced water for further fracturing. Here we review the relevant transport and geochemical properties of shales, and critically analyze the impact of water chemistry (including produced water) on these properties. We discuss five major geochemical mechanisms that are prominently involved in the temporal and spatial evolution of fractures during the stimulation and production phase: shale softening, mineral dissolution, mineral precipitation, fines migration, and wettability alteration. A higher salinity fluid creates both benefits and complications in controlling these mechanisms. For example, higher salinity fluid inhibits clay dispersion, but simultaneously requires more additives to achieve appropriate viscosity for proppant emplacement. In total this review highlights the nuances of enhanced hydrogeochemical shale stimulation in relation to the choice of fracturing fluid chemistry.

Characterization of the Pore Structure of Well Cement under Carbon Capture and Storage Conditions by an Image-Based Method with a Combination of Metal Intrusion

To more quantitatively and subtly analyze effects of carbonation on the pore structure of well cement by supercritical CO₂ under carbon capture and storage (CCS) conditions, a digital scanning electron microscopy-backscattered electron (SEM-BSE) image analysis with a combination of nontoxic low-melting point metal intrusion is used to characterize the exposed cements to humid supercritical CO₂ for 10 and 20 days. The porous area fraction (PAF) and pore size distribution (PSD) profiles obtained by slicing operation are used to describe the pore structure variation along the corrosion direction in a two-dimensional (2D) plane. The results show that the image-based method with the combination of metal intrusion is an effective method for characterizing the layer structure of exposed cement and getting quantitative information about the pore structure. From the surface to the core, the main altered layers in exposed cement for 10 days include the partially leached layer, the carbonated layer, and the calcium hydroxide (CH)-dissolved layer. For the exposed cement for 20 days, the main altered layers include the porous leached layer, the partially leached layer, the carbonated layer, and the carbonated transition layer. The nonporous carbonated layer can effectively block the flow parallel to the corrosion direction, while the porous leached layer can facilitate the flow perpendicular to the corrosion direction. Findings from this study will provide valuable information for understanding the effects of carbonation on the pore structure of well cement under CCS conditions.

Real Time 3D Observations of Portland Cement Carbonation at CO2 Storage Conditions

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.

Targeted Permeability Control in the Subsurface via Calcium Silicate Carbonation

Efforts to develop safe and effective next-generation energy and carbon-storage technologies in the subsurface require novel means to control undesired fluid migration. Here we demonstrate that the carbonation of calcium silicates can produce reaction products that dramatically reduce the permeability of porous media and that are stable. Most calcium silicates react with CO₂ to form solid carbonates but some polymorphs (here, pseudowollastonite, CaSiO₃) can react to form a range of crystalline calcium silicate hydrates (CCSHs) at intermediate pH. High-pressure (1.1-15.5 MPa) column and batch experiments were conducted at a range of temperatures (75-150 °C) and reaction products were characterized using SEM-EDS and synchrotron μXRD and μXRF. Two characteristics of CCSH precipitation were observed, revealing unique properties for permeability control relative to carbonate precipitates. First, precipitation of CCSHs tends to occur on the surface of sand grains and into pore throats, indicating that small amounts of precipitation relative to the total pore volume can effectively block flow, compared to carbonates which precipitate uniformly throughout the pore space. Second, the precipitated CCSHs are more stable at low pH conditions, which may form more secure barriers to flow, compared to carbonates, which dissolve under acidic conditions.

Meter-Scale Reactive Transport Modeling of CO2-Rich Fluid Flow along Debonded Wellbore Casing-Cement Interfaces

Defects along wellbore interfaces constitute potential pathways for CO₂ to leak from geological storage systems. In previous experimental work, we demonstrated that CO₂-induced reaction over length-scales of several meters can lead to self-sealing of such defects. In the present work, we develop a reactive transport model that, on the one hand, enables μm-mm scale exploration of reactions along debonding defects and, on the other hand, allows simulation of the large, 6 m-long samples used in our experiments. At these lengths, we find that interplay between flow velocity and reaction rate strongly affects opening/sealing of interfacial defects, and depth of chemical alteration. Carbonate precipitation in initially open defects decreases flow rate, leading to a transition from advection-dominated to diffusion-dominated reactive transport, with acidic conditions becoming progressively more confined upstream. We investigate how reaction kinetics, portlandite content, and the nature of the carbonate products impact the extent of cement alteration and permeability reduction. Notably, we observe that nonuniformity of the initial defect geometry has a profound effect on the self-sealing behavior and permeability evolution as observed on the meter scale. We infer that future wellbore models need to consider the effects of such aperture variations to obtain reliable upscaling relations.

Incorporating Nanoscale Effects into a Continuum-Scale Reactive Transport Model for CO2-Deteriorated Cement

Wellbore cement deterioration is critical for wellbore integrity and the safety of CO₂ storage in geologic formations. Our previous experimental work highlighted the importance of the portlandite (CH)-depleted zone and the surface dissolution zone in the CO₂-attacked cement. In this study, we simulated numerically the evolution of the CH-depleted zone and the dissolution of the cement surfaces utilizing a reduced-dimension (1D) reactive transport model. The approach shows that three nanoscale effects are important and had to be incorporated in a continuum-scale model to capture experimental observations: First, it was necessary to account for the fact that secondary CaCO₃ precipitation does not fill the pore space completely, with the result that acidic brine continues to diffuse through the carbonated zone to form a CH-depleted zone. Second, secondary precipitation in brine begins via nucleation kinetics, and this could not be described with previous models using growth kinetics alone. Third, our results suggest that the CaCO₃ precipitates in the confined pore space are more soluble than those formed in brine. This study provides a new platform for a reduced dimension model for CO₂ attack on cement that captures the important nanoscale mechanisms influencing macroscale phenomena in subsurface environments.

Effect of Mineral Dissolution/Precipitation and CO2 Exsolution on CO2 transport in Geological Carbon Storage

Geological carbon sequestration (GCS) in deep saline aquifers is an effective means for storing carbon dioxide to address global climate change. As the time after injection increases, the safety of storage increases as the CO₂ transforms from a separate phase to CO₂(aq) and HCO₃^- by dissolution and then to carbonates by mineral dissolution. However, subsequent depressurization could lead to dissolved CO₂(aq) escaping from the formation water and creating a new separate phase which may reduce the GCS system safety. The mineral dissolution and the CO₂ exsolution and mineral precipitation during depressurization change the morphology, porosity, and permeability of the porous rock medium, which then affects the two-phase flow of the CO₂ and formation water. A better understanding of these effects on the CO₂-water two-phase flow will improve predictions of the long-term CO₂ storage reliability, especially the impact of depressurization on the long-term stability. In this Account, we summarize our recent work on the effect of CO₂ exsolution and mineral dissolution/precipitation on CO₂ transport in GCS reservoirs. We place emphasis on understanding the behavior and transformation of the carbon components in the reservoir, including CO₂(sc/g), CO₂(aq), HCO₃^-, and carbonate minerals (calcite and dolomite), highlight their transport and mobility by coupled geochemical and two-phase flow processes, and consider the implications of these transport mechanisms on estimates of the long-term safety of GCS. We describe experimental and numerical pore- and core-scale methods used in our lab in conjunction with industrial and international partners to investigate these effects. Experimental results show how mineral dissolution affects permeability, capillary pressure, and relative permeability, which are important phenomena affecting the input parameters for reservoir flow modeling. The porosity and the absolute permeability increase when CO₂ dissolved water is continuously injected through the core. The MRI results indicate dissolution of the carbonates during the experiments since the porosity has been increased after the core-flooding experiments. The mineral dissolution changes the pore structure by enlarging the throat diameters and decreasing the pore specific surface areas, resulting in lower CO₂/water capillary pressures and changes in the relative permeability. When the reservoir pressure decreases, the CO₂ exsolution occurs due to the reduction of solubility. The CO₂ bubbles preferentially grow toward the larger pores instead of toward the throats or the finer pores during the depressurization. After exsolution, the exsolved CO₂ phase shows low mobility due to the highly dispersed pore-scale morphology, and the well dispersed small bubbles tend to merge without interface contact driven by the Ostwald ripening mechanism. During depressurization, the dissolved carbonate could also precipitate as a result of increasing pH. There is increasing formation water flow resistance and low mobility of the CO₂ in the presence of CO₂ exsolution and carbonate precipitation. These effects produce a self-sealing mechanism that may reduce unfavorable CO₂ migration even in the presence of sudden reservoir depressurization.

Influence of Chemical, Mechanical, and Transport Processes on Wellbore Leakage from Geologic CO2 Storage Reservoirs

Wells 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 mechanical alteration of cement has the capacity to seal damaged zones. Our work centers on defining the coupled chemical and mechanical processes governing flow in damaged zones in wells. We have developed process-based models, constrained by experiments, to better understand and forecast leakage risk. Leakage pathways can be sealed by precipitation of carbonate minerals in the fractures and deformation of the reacted cement. High reactivity of cement hydroxides releases excess calcium that can precipitate as carbonate solids in the fracture network under low brine flow rates. If the flow is fast, then the brine remains undersaturated with respect to the solubility of calcium carbonate minerals, and zones depleted in calcium hydroxides, enriched in calcium carbonate precipitates, and made of amorphous silicates leached of original cement minerals are formed. Under confining pressure, the reacted cement is compressed, which reduces permeability and lowers leakage risks. The broader context of this paper is to use our experimentally calibrated chemical, mechanical, and transport model to illustrate when, where, and in what conditions fracture pathways seal in CO₂ storage wells, to reduce their risk to groundwater resources. We do this by defining the amount of cement and the time required to effectively seal the leakage pathways associated with peak and postinjection overpressures, within the context of oil and gas industry standards for leak detection, mitigation, and repairs. Our simulations suggest that for many damage scenarios chemical and mechanical processes lower leakage risk by reducing or sealing fracture pathways. Leakage risk would remain high in wells with a large amount of damage, modeled here as wide fracture apertures, where fast flowing fluids are too dilute for carbonate precipitation and subsurface stress does not compress the altered cement. Fracture sealing is more likely as reservoir pressures decrease during the postinjection phase where lower fluxes aid chemical alteration and mechanical deformation of cement. Our results hold promise for the development of mitigation framework to avoid impacting groundwater resources above any geologic CO₂ storage reservoir by correlating operational pressures and barrier lengths.

Defining the Brittle Failure Envelopes of Individual Reaction Zones Observed in CO2-Exposed Wellbore Cement

To predict the behavior of the cement sheath after CO2 injection and the potential for leakage pathways, it is key to understand how the mechanical properties of the cement evolves with CO2 exposure time. We performed scratch-hardness tests on hardened samples of class G cement before and after CO2 exposure. The cement was exposed to CO2-rich fluid for one to six months at 65 °C and 8 MPa Ptotal. Detailed SEM-EDX analyses showed reaction zones similar to those previously reported in the literature: (1) an outer-reacted, porous silica-rich zone; (2) a dense, carbonated zone; and (3) a more porous, Ca-depleted inner zone. The quantitative mechanical data (brittle compressive strength and friction coefficient) obtained for each of the zones suggest that the heterogeneity of reacted cement leads to a wide range of brittle strength values in any of the reaction zones, with only a rough dependence on exposure time. However, the data can be used to guide numerical modeling efforts needed to assess the impact of reaction-induced mechanical failure of wellbore cement by coupling sensitivity analysis and mechanical predictions.

The Nanoscale Basis of CO2 Trapping for Geologic Storage

Carbon capture and storage (CCS) is likely to be a critical technology to achieve large reductions in global carbon emissions over the next century. Research on the subsurface storage of CO2 is aimed at reducing uncertainties in the efficacy of CO2 storage in sedimentary rock formations. Three key parameters that have a nanoscale basis and that contribute uncertainty to predictions of CO2 trapping are the vertical permeability kv of seals, the residual CO2 saturation Sg,r in reservoir rocks, and the reactive surface area ar of silicate minerals. This review summarizes recent progress and identifies outstanding research needs in these areas. Available data suggest that the permeability of shale and mudstone seals is heavily dependent on clay fraction and can be extremely low even in the presence of fractures. Investigations of residual CO2 trapping indicate that CO2-induced alteration in the wettability of mineral surfaces may significantly influence Sg,r. Ultimately, the rate and extent of CO2 conversion to mineral phases are uncertain due to a poor understanding of the kinetics of slow reactions between minerals and fluids. Rapidly improving characterization techniques using X-rays and neutrons, and computing capability for simulating chemical interactions, provide promise for important advances.

Effects of Sulfate during CO2 Attack on Portland Cement and Their Impacts on Mechanical Properties under Geologic CO2 Sequestration Conditions

To investigate the effects of sulfate on CO2 attack on wellbore cement (i.e., chemical and mechanical alterations) during geologic CO2 sequestration (GCS), we reacted cement samples in brine with 0.05 M sulfate and 0.4 M NaCl at 95 °C under 100 bar of either N2 or supercritical CO2. The results were compared to those obtained from systems without additional sulfate at the same temperature, pressure, salinity, and initial brine pHs. After 10 reaction days, chemical analyses using scanning electron microscopy with a backscattered electron detector (SEM-BSE) and inductively coupled plasma optical emission spectrometry (ICP-OES) showed that the CO2 attack in the presence of additional sulfate was much less severe than that in the system without additional sulfate. The results from three-point bending tests also indicated that sulfate significantly mitigated the deterioration of the cement's strength and elastic modulus. In all our systems, typical sulfate attacks on cement via formation of ettringite were not observed. The protective effects of sulfate on cement against CO2 attack resulted from sulfate adsorption, coating of CaSO4 on the CaCO3 grains in the carbonated layer, or both, which inhibited dissolution of CaCO3. Findings from this study provide new, important information for understanding the integrity of wellbores at GCS sites and thus promote safer GCS operations.

Chemical Reactions of Portland Cement with Aqueous CO2 and Their Impacts on Cement's Mechanical Properties under Geologic CO2 Sequestration Conditions

To provide information on wellbore cement integrity in the application of geologic CO2 sequestration (GCS), chemical and mechanical alterations were analyzed for cement paste samples reacted for 10 days under GCS conditions. The reactions were at 95 °C and had 100 bar of either N2 (control condition) or CO2 contacting the reaction brine solution with an ionic strength of 0.5 M adjusted by NaCl. Chemical analyses showed that the 3.0 cm × 1.1 cm × 0.3 cm samples were significantly attacked by aqueous CO2 and developed layer structures with a total attacked depth of 1220 μm. Microscale mechanical property analyses showed that the hardness and indentation modulus of the carbonated layer were 2-3 times greater than for the intact cement, but those in the portlandite-dissolved region decreased by ∼50%. The strength and elastic modulus of the bulk cement samples were reduced by 93% and 84%, respectively. The properties of the microscale regions, layer structure, microcracks, and swelling of the outer layers combined to affect the overall mechanical properties. These findings improve understanding of wellbore integrity from both chemical and mechanical viewpoints and can be utilized to improve the safety and efficiency of CO2 storage.

Determination of diffusion profiles in altered wellbore cement using X-ray computed tomography methods

The development of accurate, predictive models for use in determining wellbore integrity requires detailed information about the chemical and mechanical changes occurring in hardened Portland cements. X-ray computed tomography (XRCT) provides a method that can nondestructively probe these changes in three dimensions. Here, we describe a method for extracting subvoxel mineralogical and chemical information from synchrotron XRCT images by combining advanced image segmentation with geochemical models of cement alteration. The method relies on determining "effective linear activity coefficients" (ELAC) for the white light source to generate calibration curves that relate the image grayscales to material composition. The resulting data set supports the modeling of cement alteration by CO2-rich brine with discrete increases in calcium concentration at reaction boundaries. The results of these XRCT analyses can be used to further improve coupled geochemical and mechanical models of cement alteration in the wellbore environment.

Dissolution-Driven Permeability Reduction of a Fractured Carbonate Caprock

Geochemical reactions may alter the permeability of leakage pathways in caprocks, which serve a critical role in confining CO₂ in geologic carbon sequestration. A caprock specimen from a carbonate formation in the Michigan sedimentary Basin was fractured and studied in a high-pressure core flow experiment. Inflowing brine was saturated with CO₂ at 40°C and 10 MPa, resulting in an initial pH of 4.6, and had a calcite saturation index of -0.8. Fracture permeability decreased during the experiment, but subsequent analyses did not reveal calcite precipitation. Instead, experimental observations indicate that calcite dissolution along the fracture pathway led to mobilization of less soluble mineral particles that clogged the flow path. Analyses of core sections via electron microscopy, synchrotron-based X-ray diffraction imaging, and the first application of microbeam Ca K-edge X-ray absorption near edge structure, provided evidence that these occlusions were fragments from the host rock rather than secondary precipitates. X-ray computed tomography showed a significant loss of rock mass within preferential flow paths, suggesting that dissolution also removed critical asperities and caused mechanical closure of the fracture. The decrease in fracture permeability despite a net removal of material along the fracture pathway demonstrates a nonintuitive, inverse relationship between dissolution and permeability evolution in a fractured carbonate caprock.