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Collaborating Authors
Reservoir Characterization
Zonal Isolation Material for Low-Temperature Shallow-Depth Application: Evaluation of Early Properties Development
Agista, Madhan Nur (University of Stavanger (Corresponding author)) | Khalifeh, Mahmoud (University of Stavanger) | Saasen, Arild (University of Stavanger) | Yogarajah, Elakneswaran (Hokkaido University)
Summary Shallow-depth cementing presents unique challenges due to its low temperature and low pore pressure characteristic. The curing process of the cementitious material is typically prolonged at low temperatures resulting in a delayed curing process. The use of a low-density slurry to mitigate low pore pressure introduces another challenge, as it leads to a reduction in the final compressive strength. On the other hand, the operation requires the material to develop enough strength swiftly to be able to efficiently continue the next drilling operation. In addition, the presence of flow zones such as shallow gas and shallow water flow increases the complexity of the cementing process. There have been many developments in cementitious materials for shallow-depth cementing such as rapid-hardening cement and gas tight cement. However, there is little research focusing on the performance evaluation of each material at low-temperature conditions. This paper aims to present a thorough material evaluation for low-temperature shallow-depth cementing. The incorporated materials are American Petroleum Institute (API) Class G cement, rapid-hardening cement, gas tight cement, and geopolymer. Geopolymer is included to evaluate its potential as the green alternative to Portland-based cement. The sets of characterization were conducted during the liquid, gel, and solid phases. The samples were prepared under wide-ranging low temperatures and typical bottomhole pressures for shallow sections. The result shows different performances of each material and its behavior under low temperatures such as prolonged strength development and low reactivity, which necessitates further development of these materials.
- Asia (0.93)
- Europe > United Kingdom (0.46)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline > Geomechanics (0.69)
- Geology > Mineral > Silicate (0.69)
Binary Mixture Thermo-Chemical (BiMTheCh) Technology for Development of Low-Permeable Formations of Oil Fields in Caspian Sea
Koochi, M. Rezaei (Petroleum engineering department, Kazan Federal University, Russia) | Rojas, A. (Petroleum engineering department, Kazan Federal University, Russia) | Varfolomeev, M. A. (Petroleum engineering department, Kazan Federal University, Russia) | Khormali, A. (Chemistry department, Gonbad Kavoos University, Iran) | Lishcuk, A. N. (HMS Group Company, Moscow, Russia)
Abstract Binary mixture thermo-chemical (BiMTheCh) technology refers to energy-releasing chemicals which can be injected into the reservoir with in-situ generation of heat, nitrogen and carbon dioxide. As laboratory investigations show, BiMTheCh or thermochemical fluid has proved to be a highly effective technology for stimulation of oil wells with heavy oil and low permeability. In this work, the feasibility of this technology for stimulation of brown fields from laboratory to field scale is investigated. First, on the laboratory scale, thermobaric parameters of the reaction were studied to optimize the composition of injecting chemicals. And finally, the optimized composition is applied to enhance oil recovery from low permeable reservoirs in Russia. Laboratory results show that BiMTheCh can be used for removing asphaltene and resin from near borehole zone by melting them. Generated gases after the reaction create a network of fractures in the vicinity of the reaction zone and simultaneously, by inducing a thermobaric shock, cracks oil molecules and upgrades oil directly into the reservoir. Oil field data in 5 wells shows that oil production increased 2-3 folds with a duration of 12 months or more. BiMTheCh can be used for stimulation of green and brown fields with a high efficiency in a safe rig-less mode.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (5 more...)
Summary Numerical simulation of the CO2 storage process in porous media, such as in hydrocarbon (gas or oil) depleted reservoirs and in saline aquifers, has been the most indicated tool due to its ability to represent CO2 capacity and the different trapping mechanisms that retain CO2 in the subsurface. Given the complexity of the physicochemical phenomena involved, the modeling needs to incorporate multiphase flow, complex representation of fluids, rock, and rock-fluid interaction properties. These include CO2 reactions with aqueous species and with reservoir rock minerals, in addition to the structural and stratigraphic aspects of the reservoir heterogeneity. These phenomena need to be represented on suitable temporal and spatial scales for accurate predictions of their impacts. Currently, many studies are focused on simulating submodels or sectors of the reservoir, where using finer grids is still practical. This level of grid refinement can be prohibitive, in terms of simulation times, for modeling the entire reservoir. To address this challenge, we propose a new and practical workflow to simulate CO2 storage projects in large field-scale models. When the proposed workflow is applied in both synthetic and real field cases, simulation time is reduced by up to 96% compared to that of the fine-grid model, preserving the same results in representing the aforementioned mechanisms. The workflow is based on classical and standard approaches to handle the high simulation time, but in this study, they are structured and sequenced in three steps. The first one considers the most relevant mechanisms for CO2 storage, ranked from a high-resolution sector model. With the mechanisms prioritized in the previous step, a single-phase upscaling of petrophysical properties can be applied in the field-scale model, followed by adopting a grid with dynamic sizing. The proposed methodology is applied to saline aquifer models in this study, but it can be extended for storage in depleted hydrocarbon reservoirs.
Abstract The role of geomechanics in hydrogen extraction processes is crucial for understanding the behavior of subsurface formations and optimizing extraction techniques. This paper focuses on the modeling and rock testing aspects of geomechanics to investigate the influence of rock properties on hydrogen extraction efficiency and safety. The objective of this study is to explore the role of geomechanical modeling and rock testing in assessing reservoir behavior, wellbore stability, and storage integrity for hydrogen extraction projects. The methodology involves a comprehensive analysis of geomechanical modeling techniques and laboratory rock testing methods. Geomechanical modeling techniques, such as finite element analysis and discrete element modeling, provide valuable insights into the behavior of subsurface formations under different stress and fluid flow conditions. These models can simulate the mechanical response of the reservoir during hydrogen extraction, enabling the prediction of deformations, stress distributions, and potential failure mechanisms. The results highlight the significance of geomechanical modeling and rock testing in assessing the behavior of subsurface formations during hydrogen extraction. Geomechanical models help identify potential geomechanical risks, such as fault reactivation, induced seismicity, and wellbore instability, allowing operators to design optimal extraction strategies and implement appropriate mitigation measures. Rock testing provides crucial input parameters for accurate modeling and enhances the understanding of rock behavior, contributing to the assessment of reservoir performance and storage integrity. The conclusion drawn from this study is that geomechanical modeling and rock testing are essential tools for assessing the role of geomechanics in hydrogen extraction. By integrating these approaches, operators can gain valuable insights into the mechanical behavior of subsurface formations, optimize extraction techniques, and ensure the safe and efficient operation of hydrogen extraction projects. The innovation of this study lies in highlighting the importance of geomechanical modeling and rock testing in the context of hydrogen extraction. By incorporating these approaches, operators can make informed decisions regarding reservoir behavior, wellbore stability, and storage integrity, leading to enhanced operational efficiency and safety.
- North America (1.00)
- Asia > Middle East > Saudi Arabia > Eastern Province (0.28)
- North America > United States > Kentucky > Illinois Basin (0.99)
- North America > United States > Indiana > Illinois Basin (0.99)
- North America > United States > Illinois > Illinois Basin (0.99)
- (2 more...)
- Well Drilling > Wellbore Design (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
On-The-Fly Mixing Skid Mounted Technology Allows Cost-Effective Stimulation Jobs on Rigs with Limited Deck Space in Brazil Offshore
Carrara, M. (Baker Hughes, Macaé, Rio de Janeiro, Brazil) | Colbert, F. (Baker Hughes, Macaé, Rio de Janeiro, Brazil) | Gachet, R. (Baker Hughes, Macaé, Rio de Janeiro, Brazil) | Garcia, F. (Baker Hughes, Macaé, Rio de Janeiro, Brazil) | Pedrosa, H. (Baker Hughes, Macaé, Rio de Janeiro, Brazil) | Junior, A. (Baker Hughes, Macaé, Rio de Janeiro, Brazil) | Rezende, D. (Baker Hughes, Macaé, Rio de Janeiro, Brazil) | deSouza, J. (Baker Hughes, Macaé, Rio de Janeiro, Brazil)
Abstract While pre salt carbonate reservoirs are the main source of hydrocarbon production in Brazil (Jardim et. Al 2020), offshore mature fields located on post salt and sandstone reservoirs are still relevant. Cost effective solutions and treatment optimization are required to maximize return on investment. This paper introduces a new method to perform these jobs economically and efficiently. An overview of the operations performed on Brazilian mature fields and contingency operations for pre-salt carbonate wells including methods, strategies and benefits are reviewed. A compacted and versatile on-the-fly stimulation plant is deployed to perform acid stimulation jobs for sandstone and carbonate offshore formations. The use of this system provides the flexibility to mix several types of acidizing fluids in reduced areas, for both carbonates and sandstones, providing similar capabilities than a costly stimulation vessel, or an offshore rig with limited deck area. Concentrations of the stimulation chemicals are modified in real time, using various systems without stopping the pumping operation. This compact on-the-fly stimulation method shows many benefits, saving rig time, allowing the pumping of several chemicals, and making feasible operations that were possible only with stimulation vessel due to limited deck space of the rig. In some scenarios, large acid volumes are pumped without the need of additional acid tanks with pre-mixed acid solutions. Higher pumping rates are attained, leading to large zonal coverage treatments and rig time savings. This method has been used very successfully in Brazil since 2018 using several acidizing systems, including HCl, Mud Acid, polymeric diversion system and other acid-based technologies. Over eleven wells were treated using this on-the-fly stimulation method. Such operations take a maximum of 15 days from mobilization until demobilization. Assembly skid mounted vessels can take double or triple of the time and can increase the costs three times, which can make some projects unfeasible. This solution is switchable for low-cost projects on mature wells and workovers. The novelty is the introduction of a compact on-the-fly stimulation plant that provides with more efficient and cost-effective acid stimulation and pumping treatment allowing real-time acid concentration modification and the capability to use various acidizing technologies.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.95)
- Geology > Structural Geology > Tectonics > Salt Tectonics (0.75)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Production and Well Operations > Well Intervention (1.00)
Unraveling the Role of Water in Microwave/Electromagnetic-Assisted Catalytic Heating for Hydrogen Production from Gas Reservoirs
Yan, K. (Bob L. Herd Department of Petroleum Engineering, Texas Tech University, Lubbock, Texas, U.S.) | An, B. (Bob L. Herd Department of Petroleum Engineering, Texas Tech University, Lubbock, Texas, U.S.) | Yuan, Q. (Bob L. Herd Department of Petroleum Engineering, Texas Tech University, Lubbock, Texas, U.S.)
Abstract To cope with the increasing pressures of decarbonization that the petroleum industry is facing, a novel approach, entitled in-situ microwave/electromagnetic-assisted catalytic heating technology, is recently proposed for hydrogen (H2) production directly from petroleum reservoirs. This work investigates H2 generation from methane (CH4) cracking in the presence of sandstone rock powders under microwave irradiation through a purpose-designed lab-scale microwave reactor system. The role of water and rock minerals during reactions is also examined. The real-time variations of measured temperature of rock samples, gas flow rate, and concentration of hydrogen and other generated gases are monitored. Deuterium oxide, or the so-called heavy water (D2O), is used to track the sources of hydrogen from methene and water. A rapid temperature increase is identified for the sandstone samples during microwave heating, which is referred to as the "temperature soaring" (TS) phenomenon. The TS phenomenon happens at 560-590 ℃ under microwave irradiation at a relatively higher power. Once TS phenomenon occurs, the sample can be easily re-heated up to 700 ℃ using a low microwave power at less than 0.3 kW. The experimental results show that Fe-based and other metal minerals in the sandstone rocks have an evident natural catalytic effect for promoting CH4 conversion to H2. The H2 production with 1.0 mol.% concentration starts at a measured temperature of 392 ℃, followed by a maximum H2 concentration and CH4 conversion at 91 mol.% and 79% respectively as the temperature reaches 668 ℃. Furthermore, in the presence of D2O, a peak concentration of 4.9 mol.% D2 gas and 18.2 mol.% HD gas are generated during methane conversion to hydrogen experiments. Further, water can enhance H2 generation via coke gasification in a temperature range from 330-580 ℃. Additionally, negligible CO2 and minor CO are generated in the experiments when methane continuously flows through the sandstone samples and converted to hydrogen under microwave irradiation. The proposed technology potentially opens a new pathway for clean H2 production directly from natural gas reservoirs.
- North America > United States > Texas (0.28)
- Asia > Middle East > UAE (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Renewable > Hydrogen (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- (5 more...)
Abstract Underground Hydrogen Storage (UHS) is an emerging technology to store energy, produced by renewable sources, into subsurface porous formations. UHS efficiency in depleted gas reservoirs can be affected by H2 biochemical degradation due to interactions with rock, brine and gas. In the reservoir, subsurface microorganisms can metabolize H2 with possible hydrogen losses, H2S production, clogging and formation damage. In this work we investigate the impact of hydrogen losses due to microbial activities on UHS operations in depleted gas reservoirs lying in sandstone formations. We developed a workflow to exploit the chemical reactive transport functionalities of a commercial reservoir simulator, to model biochemical processes occurring in UHS. Kinetic chemical reaction formulation was used to replicate a Monod's type microorganism growth, using PHREEQC to tune reaction parameters by matching a 0-D process in an ideal reactor. Then, we applied the methodology to evaluate the impact of biotic reactions on UHS operations in depleted gas fields. Eventually, various sensitivities were carried out considering injection/production cycles lengths, cushion gas volumes and microbial model parameters. Benchmark against PHREEQC demonstrated that, by properly tuning the kinetic reaction model coefficients, we are capable of adequately reproduce Monod-like growth and competition of different microbial community species. Field-scale results showed that hydrogen losses due to biochemistry are limited, even though this may depend on the availability of reactants in the specific environment: in this work we focus on gas reservoirs where the molar fraction of the key nutrient, CO2, is small (< 2%) and the formation is a typical sandstone. Operational parameters, e.g. storage cycle length, have an impact on the biochemical dynamics and, then, on the hydrogen degradation and generation of undesired by-products. Similar considerations hold for the model microbial growth kinetic parameters: in this study they were established using available literature data for calibration, but we envisage to tune them using experimental results on specific reservoirs. The current model set-up does not account for rock-fluid geochemical interactions, which may result in mineral precipitation/dissolution affecting the concentration of substrates available for biotic reactions. Nonetheless, it can provide an estimate of hydrogen consumption during storage in depleted gas reservoirs due to microbial activities. This study is among the first attempts to evaluate the impact of hydrogen losses by the presence of in situ microbial populations during hydrogen storage in a realistic depleted gas field. The assessment was performed by implementing a novel workflow to encapsulate biochemical reactions and bacterial dynamic-growth in commercial reservoir simulators, which may be applied to estimate the efficiency and associated risks of future UHS projects.
- Europe > Austria (0.28)
- North America > United States (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Overview (0.67)
- Research Report > New Finding (0.54)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.88)
- Geology > Geological Subdiscipline > Geochemistry (0.66)
Flow-Geomechanics-Geochemistry Simulation of CO2 Injection into Fractured Sandstones and Carbonates
Mura, Miki (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, US.) | Sharma, Mukul M. (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX, US.)
Abstract CO2 storage in reservoirs with natural and/or induced fractures is an efficient method to sequester CO2 because of their high and sustained injectivity. Past work has focused on storage of CO2 in the pore space and in the dissolved state within the brine. This research shows that geochemical reactions involving the CO2 interacting with reservoir minerals (in different lithologies) can also play a very important role in sequestering the CO2. A fully integrated 3-D reservoir simulator that includes single-phase flow, geomechanics, and geochemistry is introduced. The geochemical capability in the simulator predicts flow and geomechanical behavior due to geochemical reactions triggered by CO2 injection. The simulation models a reservoir with an induced planar fracture. The amount of CO2 that is sequestered and the extent of mineral dissolution and precipitation are computed. To demonstrate the impact of rock lithology, the model is used to simulate CO2 injection into a sandstone, a limestone, and a dolomite reservoir. The paper also investigates two different CO2 rich brines to investigate the impact of the brine composition. It is shown that the portion of the CO2 injected that reacts with the minerals and is then converted into other mineral precipitates depends largely on the mineralogy of the reservoir and the composition of the injection fluid. Limestone and dolomite reservoirs are much more susceptible to mineral dissolution and precipitation resulting in more CO2 sequestration and larger changes in injectivity over time when injection fluid is compatible with the host rock. It is shown that the fracture geometry determines the location of mineral dissolution and precipitation. This alteration of the mechanical and flow properties of the reservoir rock and fractures resulting from mineral alteration can also change the mechanical properties of the rock and result in more fracture growth and enhance or impede propagation of CO2 plume or CO2 charged water. Results showing the pros and cons of injecting CO2 into fractured wells in sandstone and carbonate reservoirs are presented considering the brine types to charge CO2. Our results show, for the first time, the clear differences that arise when sequestering CO2 in limestone, dolomite and sandstone reservoirs. The impact of geochemical reactions in realistic injection well scenarios is quantified. Results are also presented to show the pros and cons of using hydraulically fractured wells for CO2 injection in both lithologies.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (2 more...)
Abstract Carbon Capture and Storage (CCS) is certainly the most important energy transition technology for the petroleum industry. The main objective of this process is to sequester carbon dioxide (CO2) in underground reservoirs/structures safely for many years with aim of reducing the greenhouse gas emissions and mitigating the global climate change impacts. Generally, there are four target areas for underground carbon storage. These consist of depleted oil or gas reservoirs, saline aquifers, coal beds and conventional oil reservoirs with a potential for enhance oil recovery (CO2-EOR). The current trend in the industry is mainly focused on the first two categories above. Large solubilization capacity of brine with multiple trapping mechanisms made the saline aquifer an interesting target while the existing knowledge, infrastructure in place and good injectivity are the most important factors for depleted hydrocarbon reservoirs. There are many published case studies in the literature focusing on CO2 storage in depleted gas reservoirs, however the majority of them apply to conventional dynamic flow, some with an added caprock integrity study. During producing life and CO2 injection phase in a depleted hydrocarbon reservoir, pores pressure and fluid saturation in the pore space changes affecting the fluid flow, geochemical equilibrium, and geomechanics properties of the reservoir. It is essential to establish an integrated coupled model to capture the inter-related effects of dynamic fluid flow, geochemistry and geomechanics on the storage capacity and integrity of the reservoir. During CO2 injection into depleted gas reservoirs, it is anticipated that there will be mineral dissolution or precipitation effects due to geochemical reactions that alter the rock porosity and permeability. This in turn will result in changes of the rock strength. Basically, these dynamic fluid flow, geochemical, and geomechanical changes are inter-related. Hence it is important to use an integrated coupled model that captures all these effects caused by CO2 injection to evaluate suitability of the reservoir for long-term CO2 storage. In this study, CMG's compositional simulator GEM is used to couple the dynamic fluid flow, the geochemistry, and the geomechanics to study the effects of all three changes. This provides a more accurate CO2 storage capacity estimation approach along with valuation of geomechanics such as subsidence at top of the reservoir and surface which determine the integrity of storage. For this paper a sector model extracted from a full field depleted gas reservoir with a single producer well which later converted to CO2 injector. The results of the coupled model show approximately 1% of injected CO2 in mole are mineralized in 3000 years considering geochemistry impact in the model. This translates to an equivalent increasing of storage capacity of 5-10% compared to conventional dynamic model. The results of the geochemical reactions show that initially there is some dissolution during the CO2 injection, after that within couple of hundred years there are precipitation and finally there is CO2 mineralization after 3000 years. This is mainly due to the expansion of the CO2 plume from the gas zone to the water zone. It is observed that during the production there is a subsidence of about 22 cm at the top of the reservoir and there is pore collapse due to pressure depletion in the reservoir rock. At the end of injection, subscience recovered by average of 20% of its maximum during the production. The injection can be continued until the initial reservoir pressure is reached without breaching caprock however due to rate constraint and risk of induced fracture, the injection rate is kept constant at 0.5 MMSCF/day.
- Asia (0.93)
- Europe > Austria (0.46)
- North America > United States (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.74)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Behavior of the Rock Foundation of a Concrete Dam Affected by Alkali-Aggregate Reactivity
Quirion, Marco (Hydro-Québec, Expertise intégrée - Géologie, Direction Sécurité des barrages et infrastructures, Canada ) | Dontsi-Maken, Dolice (Hydro-Québec, Intégration et ingénierie – Barrages et ouvrages régulateurs en béton, Direction Sécurité des barrages et infrastructures, Canada )
ABSTRACT: The Beauharnois dam is located near the city of Montreal (Quebec, Canada). The water intake and the powerhouse are founded directly on a quarzitic sandstone rock mass. The coarse aggregate used in the concrete to build the dam originates from these rocks and has a high reactivity to cement alkalis. This reactivity called alkali-aggregate reaction (AAR) is a slow reaction that causes the concrete to swell. Regarding the foundation, swelling of the concrete led to the transfer of stresses to the rock foundation. The intact rock is of high resistance and the rock mass of good quality. The dam foundation is stable to sliding despite the sub-horizontal bedding of the sandstone and the transferred stresses. However, it is shown that, locally, depending on the intensity and orientation of the stresses, they can contribute to the vertical opening of discontinuities near the concrete-rock interface. BEAUHARNOIS DAM The Beauharnois dam turbines a large part of the waters of the St. Lawrence River (see Figure 1). This large run-of-river power station is 1,397 m long, houses 36 turbine-generator units and is backed by a water intake with 74 passes. The particularity of Beauharnois generating station lies in its construction in three phases. Work for phases 1, 2 and 3 began in 1928, 1948 and 1956 respectively with the commissioning of each phase in 1948, 1953 and 1961. The concrete aggregates from the Beauharnois power station were obtained by crushing excavation products from the Potsdam sandstone on the development site. The cement used for the construction of the three phases was of the ordinary Portland type. The first signs of concern about the swelling of concrete came in 1940 following the observation of cracks in the concrete of phase 1 of the construction. Several investigation campaigns were carried out to conclude that the swelling was caused by a reaction between the cement alkalis and the aggregates (Bérubé et al. 2000). Nowadays, this type of reaction, called alkali-aggregate reaction (AAR), is well known (Sims & Poole 2020).
- North America > Canada > Quebec > Montreal (0.26)
- Europe > Germany > Brandenburg > Potsdam (0.25)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.67)
- Energy > Power Industry (1.00)
- Energy > Oil & Gas > Upstream (0.47)