KL
K. Li
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In CCS wells, cyclic injection of cold CO2 into the hot subsurface may lead to debonding between sealant and steel casing. We test how thermal cycling affects the sealing ability of five different types of sealant (S1 to S5) surrounding a simulated steel wellbore. We use cylindrical sealant samples with a stainless steel (AISI 316 L) pipe in the centre, cured at 150°C and 30 MPa for 28 days. Using 3 bar N2 leak tests at room temperature, we test how much the sealant-steel interface leaks before and after thermal cycling under unconfined and confined (1.5 MPa) conditions. We also conduct push-off experiments using a 500 kN loading frame before and after. For the unconfined test, we place the sample on a custom-built jig, whereas for confined tests we have a similar assembly inside a conventional triaxial vessel. The samples are brought to 60°C. Subsequently, we inject 5°C water through the central pipe at 80 mL/min for 2 mins, and let the sample reheat for 12 mins. We repeat this 16 times. Afterwards, we allow the sample to cool to room temperature, and repeat the N2 leak test in-situ. The results show that under unconfined conditions, the interface leaks more for all sealant types except S3. The key parameter controlling performance is the linear thermal expansion coefficient, where an expansion coefficient closer to that of steel indicates better performance. Under confinement, all sealant types perform better post-thermal cycling, due to the prolonged exposure to confining pressure.
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In CCS wells, cyclic injection of cold CO2 into the hot subsurface may lead to debonding between sealant and steel casing. We test how thermal cycling affects the sealing ability of five different types of sealant (S1 to S5) surrounding a simulated steel wellbore. We use cylindrical sealant samples with a stainless steel (AISI 316 L) pipe in the centre, cured at 150°C and 30 MPa for 28 days. Using 3 bar N2 leak tests at room temperature, we test how much the sealant-steel interface leaks before and after thermal cycling under unconfined and confined (1.5 MPa) conditions. We also conduct push-off experiments using a 500 kN loading frame before and after. For the unconfined test, we place the sample on a custom-built jig, whereas for confined tests we have a similar assembly inside a conventional triaxial vessel. The samples are brought to 60°C. Subsequently, we inject 5°C water through the central pipe at 80 mL/min for 2 mins, and let the sample reheat for 12 mins. We repeat this 16 times. Afterwards, we allow the sample to cool to room temperature, and repeat the N2 leak test in-situ. The results show that under unconfined conditions, the interface leaks more for all sealant types except S3. The key parameter controlling performance is the linear thermal expansion coefficient, where an expansion coefficient closer to that of steel indicates better performance. Under confinement, all sealant types perform better post-thermal cycling, due to the prolonged exposure to confining pressure.
Maintaining well integrity is a key challenge to the secure geological storage of CO2. Here, sealants based on Portland Cement form a key component, providing seals between the steel wellbore and surrounding caprock, as well as plugs for sealing wells that will no longer be used. However, exposure of sealants based on Portland Cement to CO2-bearing fluids may lead to carbonation, potentially followed by degradation of these materials during prolonged exposure or flow, which may thus negatively impact well integrity. Therefore, new sealant materials need to be developed to help ensure long-term well integrity.
This paper reports exposure of five different sealants to CO2-saturated water and wet supercritical CO2 at in-situ conditions (80 °C and 10 MPa). Three of the sealants investigated are based on Portland Cement, while the other two are based on Calcium Aluminate Cement, and a rock-based geopolymer specifically developed for Geological CO2 Storage (GCS). The five sealants were selected to represent different methods for improving wellbore seal integrity, such as restricting permeability (and porosity), or modifying how the material interacts with CO2-bearing fluids. Exposures were carried out in a purpose-built batch apparatus, enabling simultaneous exposure of up to 10 samples in total to CO2-saturated water and wet supercritical CO2.
After exposure, changes in the sealants’ microstructures and chemical and mineralogical compositions were assessed using scanning electron microscopy with energy-dispersive X-ray spectroscopy, computed tomography scanning, and fluid chemical analysis. The impact of exposure to CO2-bearing fluids was interpreted in terms of alteration and degradation of the materials, to compare how different sealant design modifications can be employed to enhance wellbore integrity. ...
This paper reports exposure of five different sealants to CO2-saturated water and wet supercritical CO2 at in-situ conditions (80 °C and 10 MPa). Three of the sealants investigated are based on Portland Cement, while the other two are based on Calcium Aluminate Cement, and a rock-based geopolymer specifically developed for Geological CO2 Storage (GCS). The five sealants were selected to represent different methods for improving wellbore seal integrity, such as restricting permeability (and porosity), or modifying how the material interacts with CO2-bearing fluids. Exposures were carried out in a purpose-built batch apparatus, enabling simultaneous exposure of up to 10 samples in total to CO2-saturated water and wet supercritical CO2.
After exposure, changes in the sealants’ microstructures and chemical and mineralogical compositions were assessed using scanning electron microscopy with energy-dispersive X-ray spectroscopy, computed tomography scanning, and fluid chemical analysis. The impact of exposure to CO2-bearing fluids was interpreted in terms of alteration and degradation of the materials, to compare how different sealant design modifications can be employed to enhance wellbore integrity. ...
Maintaining well integrity is a key challenge to the secure geological storage of CO2. Here, sealants based on Portland Cement form a key component, providing seals between the steel wellbore and surrounding caprock, as well as plugs for sealing wells that will no longer be used. However, exposure of sealants based on Portland Cement to CO2-bearing fluids may lead to carbonation, potentially followed by degradation of these materials during prolonged exposure or flow, which may thus negatively impact well integrity. Therefore, new sealant materials need to be developed to help ensure long-term well integrity.
This paper reports exposure of five different sealants to CO2-saturated water and wet supercritical CO2 at in-situ conditions (80 °C and 10 MPa). Three of the sealants investigated are based on Portland Cement, while the other two are based on Calcium Aluminate Cement, and a rock-based geopolymer specifically developed for Geological CO2 Storage (GCS). The five sealants were selected to represent different methods for improving wellbore seal integrity, such as restricting permeability (and porosity), or modifying how the material interacts with CO2-bearing fluids. Exposures were carried out in a purpose-built batch apparatus, enabling simultaneous exposure of up to 10 samples in total to CO2-saturated water and wet supercritical CO2.
After exposure, changes in the sealants’ microstructures and chemical and mineralogical compositions were assessed using scanning electron microscopy with energy-dispersive X-ray spectroscopy, computed tomography scanning, and fluid chemical analysis. The impact of exposure to CO2-bearing fluids was interpreted in terms of alteration and degradation of the materials, to compare how different sealant design modifications can be employed to enhance wellbore integrity.
This paper reports exposure of five different sealants to CO2-saturated water and wet supercritical CO2 at in-situ conditions (80 °C and 10 MPa). Three of the sealants investigated are based on Portland Cement, while the other two are based on Calcium Aluminate Cement, and a rock-based geopolymer specifically developed for Geological CO2 Storage (GCS). The five sealants were selected to represent different methods for improving wellbore seal integrity, such as restricting permeability (and porosity), or modifying how the material interacts with CO2-bearing fluids. Exposures were carried out in a purpose-built batch apparatus, enabling simultaneous exposure of up to 10 samples in total to CO2-saturated water and wet supercritical CO2.
After exposure, changes in the sealants’ microstructures and chemical and mineralogical compositions were assessed using scanning electron microscopy with energy-dispersive X-ray spectroscopy, computed tomography scanning, and fluid chemical analysis. The impact of exposure to CO2-bearing fluids was interpreted in terms of alteration and degradation of the materials, to compare how different sealant design modifications can be employed to enhance wellbore integrity.
Journal article
(2025)
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Taylor Witcher, Steffi Burchardt, Tobias Mattsson, Michael J. Heap, Anne Pluymakers, Kai Li, Peter Lazor
Volcanic and magmatic outgassing mechanisms can determine eruptive behavior of shallow silicic magma bodies. Most outgassing mechanisms proposed take place along conduit margins, where the highest strain rates drive ascending magma to brittle failure. However, these mechanisms do not account for outgassing large volumes of magma away from the conduit walls. Here, we present a continuum of porosity preserved in the microcrystalline rhyolitic Sandfell laccolith, Eastern Iceland. Three stages in the continuum are described: porous flow bands, pore channels, and fracture bands. These deformation features are present throughout the entire exposed volume of the Sandfell laccolith in meter-long band geometries, ranging from mm- to dm-scale thickness, and interlayered with coherent, undeformed rhyolite. Using microstructural analytical methods and drawing on the result of previous experimental studies, we show that emplacement-related deformation induced strain partitioning around a crystal content of 45 % that resulted in the segregation of melt-rich and melt-poorer flow bands. Subsequent deformation induced by continued magma emplacement caused strain partitioning in the melt-rich flow bands. Depending on strain rate, different types of deformation features developed, through dilation or porosity redistribution (porous flow bands), cavitation (pore channels), or tensile fracture (fracture bands). Porous flow bands have permeability values ∼4 orders of magnitude higher than undeformed rhyolite. Pore channels and fracture bands have much larger length scales, and so permeability increases dramatically in those systems. Hence, the abundance and interconnectivity of deformation features preserved in the Sandfell laccolith provided an efficient outgassing mechanism for the bulk of the intrusion. Outgassing due to viscous-brittle magma deformation during magma emplacement should therefore be considered for crystal-rich magmas, e.g., during effusive lava dome extrusion.
...
Volcanic and magmatic outgassing mechanisms can determine eruptive behavior of shallow silicic magma bodies. Most outgassing mechanisms proposed take place along conduit margins, where the highest strain rates drive ascending magma to brittle failure. However, these mechanisms do not account for outgassing large volumes of magma away from the conduit walls. Here, we present a continuum of porosity preserved in the microcrystalline rhyolitic Sandfell laccolith, Eastern Iceland. Three stages in the continuum are described: porous flow bands, pore channels, and fracture bands. These deformation features are present throughout the entire exposed volume of the Sandfell laccolith in meter-long band geometries, ranging from mm- to dm-scale thickness, and interlayered with coherent, undeformed rhyolite. Using microstructural analytical methods and drawing on the result of previous experimental studies, we show that emplacement-related deformation induced strain partitioning around a crystal content of 45 % that resulted in the segregation of melt-rich and melt-poorer flow bands. Subsequent deformation induced by continued magma emplacement caused strain partitioning in the melt-rich flow bands. Depending on strain rate, different types of deformation features developed, through dilation or porosity redistribution (porous flow bands), cavitation (pore channels), or tensile fracture (fracture bands). Porous flow bands have permeability values ∼4 orders of magnitude higher than undeformed rhyolite. Pore channels and fracture bands have much larger length scales, and so permeability increases dramatically in those systems. Hence, the abundance and interconnectivity of deformation features preserved in the Sandfell laccolith provided an efficient outgassing mechanism for the bulk of the intrusion. Outgassing due to viscous-brittle magma deformation during magma emplacement should therefore be considered for crystal-rich magmas, e.g., during effusive lava dome extrusion.
In geological CO2 storage, the integrity of seals between well and caprock is crucial for ensuring permanent CO2 storage. One key mechanism that might affect this integrity is thermal cycling when cold CO2 is injected periodically into a hot reservoir. Our study aims to identify which properties of a sealant are key to its ability to withstand thermal cycling under in-situ conditions. We investigate sealants of four different compositions, namely two ordinary Portland cement-based blends (S1 and S2), and two blends designed for carbon capture and storage applications, namely a novel ordinary Portland cement-based blend with CO2-sequestering additives (S3), and a calcium aluminate cement-based blend (S4). These four sealants possess different thermomechanical properties, such as Young’s modulus, tensile strength, unconfined compressive strength, thermal diffusivity, and thermal expansion coefficient, also characterized in this study. Samples of these sealants were placed in a triaxial deformation apparatus, and subjected to either 1.5 or 10 MPa confinement at 120 °C. Then we applied eight thermal cycles by injecting 20 °C water through a central bore in these samples. To assess the effects of the thermal treatment, we used X-ray micro-computed tomography (micro-CT), helium pycnometry, and compressive strength testing on thermal-treated as well as intact samples. Micro-CT results indicate that all sealant samples maintained integrity without cracking (above 32 µm) after thermal cycling under confinement. For all four sealants, post-treatment porosity (determined by either micro-CT or pycnometer) was reduced, which is ascribed to compression during confinement. This reduction in porosity was associated with an increase in compressive strength. Compared to experiments conducted under 1.5 MPa confinement, those at 10 MPa exhibit a greater reduction in porosity, and more enhanced compressive strength. The application of confinement suppressed the potential of crack formation by increasing the effective strength including tensile strength of the sealant during thermal cycling by a reduction in porosity. Based on these findings, we conclude that to limit potential damage to seal integrity induced by thermal cycling, sealants for carbon capture and storage should ideally have high tensile strength and thermal diffusivity, but low Young’s modulus and thermal expansion coefficient.
...
In geological CO2 storage, the integrity of seals between well and caprock is crucial for ensuring permanent CO2 storage. One key mechanism that might affect this integrity is thermal cycling when cold CO2 is injected periodically into a hot reservoir. Our study aims to identify which properties of a sealant are key to its ability to withstand thermal cycling under in-situ conditions. We investigate sealants of four different compositions, namely two ordinary Portland cement-based blends (S1 and S2), and two blends designed for carbon capture and storage applications, namely a novel ordinary Portland cement-based blend with CO2-sequestering additives (S3), and a calcium aluminate cement-based blend (S4). These four sealants possess different thermomechanical properties, such as Young’s modulus, tensile strength, unconfined compressive strength, thermal diffusivity, and thermal expansion coefficient, also characterized in this study. Samples of these sealants were placed in a triaxial deformation apparatus, and subjected to either 1.5 or 10 MPa confinement at 120 °C. Then we applied eight thermal cycles by injecting 20 °C water through a central bore in these samples. To assess the effects of the thermal treatment, we used X-ray micro-computed tomography (micro-CT), helium pycnometry, and compressive strength testing on thermal-treated as well as intact samples. Micro-CT results indicate that all sealant samples maintained integrity without cracking (above 32 µm) after thermal cycling under confinement. For all four sealants, post-treatment porosity (determined by either micro-CT or pycnometer) was reduced, which is ascribed to compression during confinement. This reduction in porosity was associated with an increase in compressive strength. Compared to experiments conducted under 1.5 MPa confinement, those at 10 MPa exhibit a greater reduction in porosity, and more enhanced compressive strength. The application of confinement suppressed the potential of crack formation by increasing the effective strength including tensile strength of the sealant during thermal cycling by a reduction in porosity. Based on these findings, we conclude that to limit potential damage to seal integrity induced by thermal cycling, sealants for carbon capture and storage should ideally have high tensile strength and thermal diffusivity, but low Young’s modulus and thermal expansion coefficient.
This paper reports exposure of five different sealants to simulated well conditions with supercritical CO2 containing H2S or H2SO4 as impurities. Three of these sealants are based on Portland Cement, while the other two are based on Calcium Aluminate Cement, and a rock-based geopolymer specifically developed for Geological CO2 Storage (GCS). The impact of the impurities on these sealants was assessed through scanning electron microscopy with energy-dispersive X-ray spectroscopy, computed tomography scanning, and fluid chemical analysis, and compared to previous research where the same five sealants were exposed to clean CO2 under otherwise identical conditions.
The results show that during exposure to CO2-saturated water, the presence of H2S mostly resulted in enhanced sealant alteration depths, and reduced carbonate precipitation. During exposure to wet supercritical CO2, the presence of H2S or H2SO4 resulted in reduced carbonate precipitation, and enhanced alteration depths in some (H2S) or all (H2SO4) sealants. Additionally, relatively minor degradation was observed in the outer 100–200 μm of samples exposed in the presence of H2SO4. Overall, the impacts of impurities were more pronounced for sealants that were more affected by exposure to clean CO2. ...
The results show that during exposure to CO2-saturated water, the presence of H2S mostly resulted in enhanced sealant alteration depths, and reduced carbonate precipitation. During exposure to wet supercritical CO2, the presence of H2S or H2SO4 resulted in reduced carbonate precipitation, and enhanced alteration depths in some (H2S) or all (H2SO4) sealants. Additionally, relatively minor degradation was observed in the outer 100–200 μm of samples exposed in the presence of H2SO4. Overall, the impacts of impurities were more pronounced for sealants that were more affected by exposure to clean CO2. ...
This paper reports exposure of five different sealants to simulated well conditions with supercritical CO2 containing H2S or H2SO4 as impurities. Three of these sealants are based on Portland Cement, while the other two are based on Calcium Aluminate Cement, and a rock-based geopolymer specifically developed for Geological CO2 Storage (GCS). The impact of the impurities on these sealants was assessed through scanning electron microscopy with energy-dispersive X-ray spectroscopy, computed tomography scanning, and fluid chemical analysis, and compared to previous research where the same five sealants were exposed to clean CO2 under otherwise identical conditions.
The results show that during exposure to CO2-saturated water, the presence of H2S mostly resulted in enhanced sealant alteration depths, and reduced carbonate precipitation. During exposure to wet supercritical CO2, the presence of H2S or H2SO4 resulted in reduced carbonate precipitation, and enhanced alteration depths in some (H2S) or all (H2SO4) sealants. Additionally, relatively minor degradation was observed in the outer 100–200 μm of samples exposed in the presence of H2SO4. Overall, the impacts of impurities were more pronounced for sealants that were more affected by exposure to clean CO2.
The results show that during exposure to CO2-saturated water, the presence of H2S mostly resulted in enhanced sealant alteration depths, and reduced carbonate precipitation. During exposure to wet supercritical CO2, the presence of H2S or H2SO4 resulted in reduced carbonate precipitation, and enhanced alteration depths in some (H2S) or all (H2SO4) sealants. Additionally, relatively minor degradation was observed in the outer 100–200 μm of samples exposed in the presence of H2SO4. Overall, the impacts of impurities were more pronounced for sealants that were more affected by exposure to clean CO2.
Sealants that can guarantee long-term wellbore sealing integrity are of great significance to the safe and sustainable storage of CO2 in carbon capture and storage (CCS). In this study, we investigate how abrupt cyclic thermal shocks affect the integrity of four sealants of different compositions. These sealants include two reference OPC-based blends (S1 and S2), one newly-designed OPC-based blend that contains CO2-sequestering additives (S3), and one calcium aluminate cement (CAC)-based blend designed for CCS applications (S4). We have measured the thermal properties of these samples, followed by quenching and flow-through experiments to apply strong cyclic thermal shocks on samples of the four sealants, where we heated the samples to 120 °C, and quenched them in, or flowed through water of 20 °C. Using X-ray tomography (32 µm/voxel) before and after the experiment showed that both S1, S2 (reference OPC-based) and S4 (CAC-based) broke after thermal-shocking experiments. Cracks and new voids developed in the samples. Post-treatment strength testing shows that thermal shocks reduce the unconfined compressive strength of these three sealants. This implies that these compositions may not be optimal materials for long-term wellbore sealing during CO2 injection and storage afterward. For all these three sealant compositions, quenching resulted in a greater reduction in strength (by 53 % on average) than flow-through experiments (by 29 % on average). On the contrary, we have not observed any cracks after either quenching or flow-through experiments in S3 sealant (OPC with CO2-sequestering additives). We attribute the intactness of this sealant after thermal shocks to its higher thermal diffusivity than the other three sealants. Heat transfers more rapidly in this sealant and the associated thermal stresses are mild and insufficient to cause any damage to its integrity, which makes this sealant a good candidate for wellbore sealing material that can effectively withstand strong thermal shocks encountered during CCS, though further studies are required.
...
Sealants that can guarantee long-term wellbore sealing integrity are of great significance to the safe and sustainable storage of CO2 in carbon capture and storage (CCS). In this study, we investigate how abrupt cyclic thermal shocks affect the integrity of four sealants of different compositions. These sealants include two reference OPC-based blends (S1 and S2), one newly-designed OPC-based blend that contains CO2-sequestering additives (S3), and one calcium aluminate cement (CAC)-based blend designed for CCS applications (S4). We have measured the thermal properties of these samples, followed by quenching and flow-through experiments to apply strong cyclic thermal shocks on samples of the four sealants, where we heated the samples to 120 °C, and quenched them in, or flowed through water of 20 °C. Using X-ray tomography (32 µm/voxel) before and after the experiment showed that both S1, S2 (reference OPC-based) and S4 (CAC-based) broke after thermal-shocking experiments. Cracks and new voids developed in the samples. Post-treatment strength testing shows that thermal shocks reduce the unconfined compressive strength of these three sealants. This implies that these compositions may not be optimal materials for long-term wellbore sealing during CO2 injection and storage afterward. For all these three sealant compositions, quenching resulted in a greater reduction in strength (by 53 % on average) than flow-through experiments (by 29 % on average). On the contrary, we have not observed any cracks after either quenching or flow-through experiments in S3 sealant (OPC with CO2-sequestering additives). We attribute the intactness of this sealant after thermal shocks to its higher thermal diffusivity than the other three sealants. Heat transfers more rapidly in this sealant and the associated thermal stresses are mild and insufficient to cause any damage to its integrity, which makes this sealant a good candidate for wellbore sealing material that can effectively withstand strong thermal shocks encountered during CCS, though further studies are required.
The development of new geological storage applications and other uses of subsurface reservoirs requires tailored wellbore sealants, able to withstand application-specific exposure conditions. For example, wellbore sealants used in reservoirs targeted for CO2-storage will be exposed to CO2-rich fluids, that may chemically attack OPC-based sealants, leading to carbonation and potential degradation. During CO2-injection, local temperature changes around the injection well may also affect the integrity of the sealant-wellbore system, for example causing the formation of annuli between sealant and steel casing due to differences in thermal expansion. The research project CEMENTEGRITY aims to identify the key sealant properties that may help to ensure the long-term integrity of the wellbore-seal system during CO2-injection and storage, as well as the best testing methods for these properties. This is done by testing five different sealant compositions, exposing them to potentially deleterious impacts under different conditions. Here, we report some of the key findings of our project. While CEMENTEGRITY is researching sealants specifically for CO2-storage, other applications, such as hydrogen storage, or geothermal energy exploitation, will require purpose-built sealants that are similarly tailored to the expected chemical and physical conditions.
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The development of new geological storage applications and other uses of subsurface reservoirs requires tailored wellbore sealants, able to withstand application-specific exposure conditions. For example, wellbore sealants used in reservoirs targeted for CO2-storage will be exposed to CO2-rich fluids, that may chemically attack OPC-based sealants, leading to carbonation and potential degradation. During CO2-injection, local temperature changes around the injection well may also affect the integrity of the sealant-wellbore system, for example causing the formation of annuli between sealant and steel casing due to differences in thermal expansion. The research project CEMENTEGRITY aims to identify the key sealant properties that may help to ensure the long-term integrity of the wellbore-seal system during CO2-injection and storage, as well as the best testing methods for these properties. This is done by testing five different sealant compositions, exposing them to potentially deleterious impacts under different conditions. Here, we report some of the key findings of our project. While CEMENTEGRITY is researching sealants specifically for CO2-storage, other applications, such as hydrogen storage, or geothermal energy exploitation, will require purpose-built sealants that are similarly tailored to the expected chemical and physical conditions.
Carbon capture and storage (CCS) gains much attention as it contributes to mitigating climate change. However, during CCS, the periodic injection of pressurized CO2 leads to strong thermal cycling and shocks in the subsurface, due to the endothermic expansion of pressurized CO2 upon injection. Under these temperature variations, the wellbore and subsurface formations cyclically contract and expand. As a result, leakage pathways such as micro-annuli between wellbore casing and cement, and cracks in the cement can develop. They impair well integrity, and thus impede safe geological storage of CO2. Therefore it is of significance to understand how the sealing ability of the cement sheath of CCS wells is affected by thermal cycling or shocks.
In this paper, we report a novel technique to investigate cracking in cement by thermal shocks under in-situ temperature and pressure. To this end, we use a triaxial deformation apparatus capable of mounting a cement sample in a vessel at a confining pressure of up to 70 MPa, with an axial stress up to 26 MPa. An internal furnace is used to achieve an elevated temperature in the vessel. Pore fluid lines are fitted in upper and lower axial pistons to allow water injection. In this study, we use a solid neat cement sample (∅30×70 mm, water-to-cement ratio: 0.3) cured at 20ºC and ambient pressure for 28 days. During the experiments, the triaxial vessel is filled with heat-resistant oil which provides the confining pressure. The cement sample is isolated from the oil using a thin Teflon jacket. We load the sample at different in-situ states of hydrostatic stress and heat the sample assembly to various elevated temperatures (60 - 120ºC). We then inject cold water (20ºC) through the sample using two high-pressure syringe pumps at a designated flow rate for a given time. In the vessel, three linear variable differential transducers (LVDT) mounted parallel to, and span around the sample are used to calculate axial and radial strain, respectively. Two thermocouples, one mounted on the middle of the sample (outside the jacket), and another inside the upper pore fluid line, are used to measure temperature. To study how and where cracks initiate and grow in the cement under thermal shocks, we measure permeability with a differential pressure transducer measuring the difference between the up- and down-stream pore fluid line, and we use a micro-computed tomography (μ-CT) scanner to characterize the microstructure of the cement sample before and after the experiments. This provides valuable expedience to investigate the thermal effects on the integrity of cement under different in-situ conditions for CCS wells. The pistons of the setup can also be readily adjusted to study how de-bonding between casing and cement, and cracks in the cement develop for composite cement samples (with analogous casing) under thermal cycling. ...
In this paper, we report a novel technique to investigate cracking in cement by thermal shocks under in-situ temperature and pressure. To this end, we use a triaxial deformation apparatus capable of mounting a cement sample in a vessel at a confining pressure of up to 70 MPa, with an axial stress up to 26 MPa. An internal furnace is used to achieve an elevated temperature in the vessel. Pore fluid lines are fitted in upper and lower axial pistons to allow water injection. In this study, we use a solid neat cement sample (∅30×70 mm, water-to-cement ratio: 0.3) cured at 20ºC and ambient pressure for 28 days. During the experiments, the triaxial vessel is filled with heat-resistant oil which provides the confining pressure. The cement sample is isolated from the oil using a thin Teflon jacket. We load the sample at different in-situ states of hydrostatic stress and heat the sample assembly to various elevated temperatures (60 - 120ºC). We then inject cold water (20ºC) through the sample using two high-pressure syringe pumps at a designated flow rate for a given time. In the vessel, three linear variable differential transducers (LVDT) mounted parallel to, and span around the sample are used to calculate axial and radial strain, respectively. Two thermocouples, one mounted on the middle of the sample (outside the jacket), and another inside the upper pore fluid line, are used to measure temperature. To study how and where cracks initiate and grow in the cement under thermal shocks, we measure permeability with a differential pressure transducer measuring the difference between the up- and down-stream pore fluid line, and we use a micro-computed tomography (μ-CT) scanner to characterize the microstructure of the cement sample before and after the experiments. This provides valuable expedience to investigate the thermal effects on the integrity of cement under different in-situ conditions for CCS wells. The pistons of the setup can also be readily adjusted to study how de-bonding between casing and cement, and cracks in the cement develop for composite cement samples (with analogous casing) under thermal cycling. ...
Carbon capture and storage (CCS) gains much attention as it contributes to mitigating climate change. However, during CCS, the periodic injection of pressurized CO2 leads to strong thermal cycling and shocks in the subsurface, due to the endothermic expansion of pressurized CO2 upon injection. Under these temperature variations, the wellbore and subsurface formations cyclically contract and expand. As a result, leakage pathways such as micro-annuli between wellbore casing and cement, and cracks in the cement can develop. They impair well integrity, and thus impede safe geological storage of CO2. Therefore it is of significance to understand how the sealing ability of the cement sheath of CCS wells is affected by thermal cycling or shocks.
In this paper, we report a novel technique to investigate cracking in cement by thermal shocks under in-situ temperature and pressure. To this end, we use a triaxial deformation apparatus capable of mounting a cement sample in a vessel at a confining pressure of up to 70 MPa, with an axial stress up to 26 MPa. An internal furnace is used to achieve an elevated temperature in the vessel. Pore fluid lines are fitted in upper and lower axial pistons to allow water injection. In this study, we use a solid neat cement sample (∅30×70 mm, water-to-cement ratio: 0.3) cured at 20ºC and ambient pressure for 28 days. During the experiments, the triaxial vessel is filled with heat-resistant oil which provides the confining pressure. The cement sample is isolated from the oil using a thin Teflon jacket. We load the sample at different in-situ states of hydrostatic stress and heat the sample assembly to various elevated temperatures (60 - 120ºC). We then inject cold water (20ºC) through the sample using two high-pressure syringe pumps at a designated flow rate for a given time. In the vessel, three linear variable differential transducers (LVDT) mounted parallel to, and span around the sample are used to calculate axial and radial strain, respectively. Two thermocouples, one mounted on the middle of the sample (outside the jacket), and another inside the upper pore fluid line, are used to measure temperature. To study how and where cracks initiate and grow in the cement under thermal shocks, we measure permeability with a differential pressure transducer measuring the difference between the up- and down-stream pore fluid line, and we use a micro-computed tomography (μ-CT) scanner to characterize the microstructure of the cement sample before and after the experiments. This provides valuable expedience to investigate the thermal effects on the integrity of cement under different in-situ conditions for CCS wells. The pistons of the setup can also be readily adjusted to study how de-bonding between casing and cement, and cracks in the cement develop for composite cement samples (with analogous casing) under thermal cycling.
In this paper, we report a novel technique to investigate cracking in cement by thermal shocks under in-situ temperature and pressure. To this end, we use a triaxial deformation apparatus capable of mounting a cement sample in a vessel at a confining pressure of up to 70 MPa, with an axial stress up to 26 MPa. An internal furnace is used to achieve an elevated temperature in the vessel. Pore fluid lines are fitted in upper and lower axial pistons to allow water injection. In this study, we use a solid neat cement sample (∅30×70 mm, water-to-cement ratio: 0.3) cured at 20ºC and ambient pressure for 28 days. During the experiments, the triaxial vessel is filled with heat-resistant oil which provides the confining pressure. The cement sample is isolated from the oil using a thin Teflon jacket. We load the sample at different in-situ states of hydrostatic stress and heat the sample assembly to various elevated temperatures (60 - 120ºC). We then inject cold water (20ºC) through the sample using two high-pressure syringe pumps at a designated flow rate for a given time. In the vessel, three linear variable differential transducers (LVDT) mounted parallel to, and span around the sample are used to calculate axial and radial strain, respectively. Two thermocouples, one mounted on the middle of the sample (outside the jacket), and another inside the upper pore fluid line, are used to measure temperature. To study how and where cracks initiate and grow in the cement under thermal shocks, we measure permeability with a differential pressure transducer measuring the difference between the up- and down-stream pore fluid line, and we use a micro-computed tomography (μ-CT) scanner to characterize the microstructure of the cement sample before and after the experiments. This provides valuable expedience to investigate the thermal effects on the integrity of cement under different in-situ conditions for CCS wells. The pistons of the setup can also be readily adjusted to study how de-bonding between casing and cement, and cracks in the cement develop for composite cement samples (with analogous casing) under thermal cycling.
Foam is applied in enhanced oil recovery to improve the sweep of injected gas and increase oil recovery, by greatly reducing the mobility of gas. In the laboratory, X-ray computed tomography is commonly used to evaluate the performance of foam in core plugs. However, foam properties, such as bubble size and capillary pressure, are much more difficult to measure. In recent years, microfluidic models have gained much attention because they easily facilitate the imaging study of in-situ foam. However, it is still challenging to estimate capillary pressure, in a model with a uniform depth of etching. In this paper, we report a novel technique to estimate water saturation and capillary pressure of foam in two 1-meter-long model fractures. Both model fractures are made of glass plates. They have different roughness and hydraulic apertures. Unlike microfluidics with uniform depth of etching, our model fractures each has a variation of aperture. We characterize the roughness and represent the aperture distribution of the fracture as a network of pore bodies and pore throats. In this study, foam is pre-generated and then injected into the fractures. The inlet and outlet valves are closed for 24 hr after foam reaches steady-state. We use a high-speed camera to visualize foam in the fractures. We use ImageJ software to analyze foam texture and quantify bubble density, average bubble size and polydispersivity. In addition, we estimate water saturation and capillary pressure by analyzing images in terms of fracture geometry. We found that water in foam resides in locations of narrow aperture, Plateau borders, lamellae between bubbles, and water films on glass walls. Water-filled zones of narrow aperture and Plateau borders account for almost all the water. During the re-distribution of water and gas in static foam, in-flow and out-flow of water must take paths along the network of Plateau borders and water-occupied zones, as they are the only continuous paths for water flow. In both model fractures, the decrease in water saturation coincides with an increase in capillary pressure, as expected. This novel technique of estimation of water saturation and capillary pressure of foam provides insights for studies of foam in naturally fractured reservoirs with complex geometry, where measuring such foam properties is challenging. This analysis is possible because aperture varies along our model fractures, unlike most microfluidic devices. Our technique would also have an application to foam aquifer remediation and CO
2 sequestration.
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Foam is applied in enhanced oil recovery to improve the sweep of injected gas and increase oil recovery, by greatly reducing the mobility of gas. In the laboratory, X-ray computed tomography is commonly used to evaluate the performance of foam in core plugs. However, foam properties, such as bubble size and capillary pressure, are much more difficult to measure. In recent years, microfluidic models have gained much attention because they easily facilitate the imaging study of in-situ foam. However, it is still challenging to estimate capillary pressure, in a model with a uniform depth of etching. In this paper, we report a novel technique to estimate water saturation and capillary pressure of foam in two 1-meter-long model fractures. Both model fractures are made of glass plates. They have different roughness and hydraulic apertures. Unlike microfluidics with uniform depth of etching, our model fractures each has a variation of aperture. We characterize the roughness and represent the aperture distribution of the fracture as a network of pore bodies and pore throats. In this study, foam is pre-generated and then injected into the fractures. The inlet and outlet valves are closed for 24 hr after foam reaches steady-state. We use a high-speed camera to visualize foam in the fractures. We use ImageJ software to analyze foam texture and quantify bubble density, average bubble size and polydispersivity. In addition, we estimate water saturation and capillary pressure by analyzing images in terms of fracture geometry. We found that water in foam resides in locations of narrow aperture, Plateau borders, lamellae between bubbles, and water films on glass walls. Water-filled zones of narrow aperture and Plateau borders account for almost all the water. During the re-distribution of water and gas in static foam, in-flow and out-flow of water must take paths along the network of Plateau borders and water-occupied zones, as they are the only continuous paths for water flow. In both model fractures, the decrease in water saturation coincides with an increase in capillary pressure, as expected. This novel technique of estimation of water saturation and capillary pressure of foam provides insights for studies of foam in naturally fractured reservoirs with complex geometry, where measuring such foam properties is challenging. This analysis is possible because aperture varies along our model fractures, unlike most microfluidic devices. Our technique would also have an application to foam aquifer remediation and CO 2 sequestration.
Carbon capture and storage (CCS) gains much attention as it contributes to mitigating climate change. However, during CCS, the periodic injection of pressurized CO2 leads to strong thermal cycling and shocks in the subsurface, due to the endothermic expansion of pressurized CO2 upon injection. Under these temperature variations, the wellbore and subsurface formations cyclically contract and expand. As a result, leakage pathways such as micro-annuli between wellbore casing and cement, and cracks in the cement can develop. They impair well integrity, and thus impede safe geological storage of CO2. Therefore it is of significance to understand how the sealing ability of the cement sheath of CCS wells is affected by thermal cycling or shocks.
In this paper, we report a novel technique to investigate cracking in cement by thermal shocks under in-situ temperature and pressure. To this end, we use a triaxial deformation apparatus capable of mounting a cement sample in a vessel at a confining pressure of up to 70 MPa, with an axial stress up to 26 MPa. An internal furnace is used to achieve an elevated temperature in the vessel. Pore fluid lines are fitted in upper and lower axial pistons to allow water injection. In this study, we use a solid neat cement sample (∅30×70 mm, water-to-cement ratio: 0.3) cured at 20ºC and ambient pressure for 28 days. During the experiments, the triaxial vessel is filled with heat-resistant oil which provides the confining pressure. The cement sample is isolated from the oil using a thin Teflon jacket. We load the sample at different in-situ states of hydrostatic stress and heat the sample assembly to various elevated temperatures (60 - 120ºC). We then inject cold water (20ºC) through the sample using two high-pressure syringe pumps at a designated flow rate for a given time. In the vessel, three linear variable differential transducers (LVDT) mounted parallel to, and span around the sample are used to calculate axial and radial strain, respectively. Two thermocouples, one mounted on the middle of the sample (outside the jacket), and another inside the upper pore fluid line, are used to measure temperature. To study the extent of cracking, how and where cracks initiate and grow in the cement under thermal shocks, we measure permeability of the sample with a differential pressure transducer measuring the difference between the up- and down-stream pore fluid line, and we use a micro-computed tomography (μ-CT) scanner to characterize the microstructure of the cement sample before and after the experiments. This technique provides valuable expedience to investigate the thermal effects on the integrity of cement under different in-situ conditions for CCS wells.
The pistons of the setup can also be readily adjusted to study how de-bonding between casing and cement, and cracks in the cement develop for composite cement samples (with analogous casing) under thermal cycling. Our overall goal by using these techniques is to develop and test novel cement designs for enhanced CCS well integrity.
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Carbon capture and storage (CCS) gains much attention as it contributes to mitigating climate change. However, during CCS, the periodic injection of pressurized CO2 leads to strong thermal cycling and shocks in the subsurface, due to the endothermic expansion of pressurized CO2 upon injection. Under these temperature variations, the wellbore and subsurface formations cyclically contract and expand. As a result, leakage pathways such as micro-annuli between wellbore casing and cement, and cracks in the cement can develop. They impair well integrity, and thus impede safe geological storage of CO2. Therefore it is of significance to understand how the sealing ability of the cement sheath of CCS wells is affected by thermal cycling or shocks.
In this paper, we report a novel technique to investigate cracking in cement by thermal shocks under in-situ temperature and pressure. To this end, we use a triaxial deformation apparatus capable of mounting a cement sample in a vessel at a confining pressure of up to 70 MPa, with an axial stress up to 26 MPa. An internal furnace is used to achieve an elevated temperature in the vessel. Pore fluid lines are fitted in upper and lower axial pistons to allow water injection. In this study, we use a solid neat cement sample (∅30×70 mm, water-to-cement ratio: 0.3) cured at 20ºC and ambient pressure for 28 days. During the experiments, the triaxial vessel is filled with heat-resistant oil which provides the confining pressure. The cement sample is isolated from the oil using a thin Teflon jacket. We load the sample at different in-situ states of hydrostatic stress and heat the sample assembly to various elevated temperatures (60 - 120ºC). We then inject cold water (20ºC) through the sample using two high-pressure syringe pumps at a designated flow rate for a given time. In the vessel, three linear variable differential transducers (LVDT) mounted parallel to, and span around the sample are used to calculate axial and radial strain, respectively. Two thermocouples, one mounted on the middle of the sample (outside the jacket), and another inside the upper pore fluid line, are used to measure temperature. To study the extent of cracking, how and where cracks initiate and grow in the cement under thermal shocks, we measure permeability of the sample with a differential pressure transducer measuring the difference between the up- and down-stream pore fluid line, and we use a micro-computed tomography (μ-CT) scanner to characterize the microstructure of the cement sample before and after the experiments. This technique provides valuable expedience to investigate the thermal effects on the integrity of cement under different in-situ conditions for CCS wells.
The pistons of the setup can also be readily adjusted to study how de-bonding between casing and cement, and cracks in the cement develop for composite cement samples (with analogous casing) under thermal cycling. Our overall goal by using these techniques is to develop and test novel cement designs for enhanced CCS well integrity.
During carbon capture and storage (CCS), the periodic injection of pressurized CO2 leads to thermal cycling and shocks in the subsurface, due to the endothermic expansion of pressurized CO2 upon injection. Under these temperature variations, micro-annuli between wellbore casing and cement, and cracks in the cement can develop. They impede the safe geological storage of CO2. Therefore it is of significance to understand how the sealing ability of the cement sheath of CCS wells is affected by thermal cycling or shocks. This paper reports a novel technique to investigate cracking in cement by thermal shocks under in-situ conditions. We use a triaxial deformation apparatus capable of mounting a cement sample in a vessel at a confining pressure of up to 70 MPa, with axial stress up to 26 MPa. An internal furnace is used to achieve an elevated temperature in the vessel. Pore fluid lines are fitted in upper and lower axial pistons to allow water injection. During the experiments, the triaxial vessel is filled with heat-resistant oil which provides the confining pressure. We load the sample at different in-situ states of hydrostatic stress and heat the sample assembly to various elevated temperatures (60 - 120ºC). We then inject cold water (20ºC) through the sample using two high-pressure syringe pumps at a designated flow rate for a given time. To study how thermal shocks affect cement, we measure permeability with a differential pressure transducer measuring the difference between the up- and down-stream pore fluid line, and we use micro-computed tomography to characterize the microstructure of the cement sample before and after the experiments.
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During carbon capture and storage (CCS), the periodic injection of pressurized CO2 leads to thermal cycling and shocks in the subsurface, due to the endothermic expansion of pressurized CO2 upon injection. Under these temperature variations, micro-annuli between wellbore casing and cement, and cracks in the cement can develop. They impede the safe geological storage of CO2. Therefore it is of significance to understand how the sealing ability of the cement sheath of CCS wells is affected by thermal cycling or shocks. This paper reports a novel technique to investigate cracking in cement by thermal shocks under in-situ conditions. We use a triaxial deformation apparatus capable of mounting a cement sample in a vessel at a confining pressure of up to 70 MPa, with axial stress up to 26 MPa. An internal furnace is used to achieve an elevated temperature in the vessel. Pore fluid lines are fitted in upper and lower axial pistons to allow water injection. During the experiments, the triaxial vessel is filled with heat-resistant oil which provides the confining pressure. We load the sample at different in-situ states of hydrostatic stress and heat the sample assembly to various elevated temperatures (60 - 120ºC). We then inject cold water (20ºC) through the sample using two high-pressure syringe pumps at a designated flow rate for a given time. To study how thermal shocks affect cement, we measure permeability with a differential pressure transducer measuring the difference between the up- and down-stream pore fluid line, and we use micro-computed tomography to characterize the microstructure of the cement sample before and after the experiments.
Naturally fractured reservoirs (NFRs) gain much attention worldwide because they are often encountered in aquifer remediation, CO2 sequestration, and hydrocarbon extraction. In hydrocarbon extraction, however, oil recovery by gas injection in NFRs is usually low, because of poor sweep efficiency. During gas injection, the displacement front is unstable. Conformance problems, such as gravity override, viscous fingering, and channeling, take place because the gas has a lighter density and lower viscosity compared to reservoir fluids, and tends to flow preferably through high-permeability zones in heterogeneous reservoirs. In addition, open fractures can have much greater conductivity than the matrix. As a result, gas flows through fractures, leaving much of the matrix unswept. Foam, by adding surfactant solution to gas injection, can effectively mitigate conformance problems by greatly reducing the mobility of gas. During foam flooding in porous media, the displacement front is more stable, and more gas is diverted to unswept zones, hence improving the sweep and increasing oil recovery. Foam can also be created in fractures, where it builds up a viscous pressure gradient and thus diverts the flow of gas into the matrix. As a result, the sweep is improved. In the field, foam pilots have achieved an increase in oil production rate and a reduction in gas/oil ratio. Despite this success, foam application in NFRs is still much less understood than in unfractured porous media. In this dissertation, we aim to expand our understanding of foam in fractures through an experimental approach. To this end, we create four 1-m-long, 15-cm-wide glass model fractures (Models A, B, C and D) with different roughness and hydraulic apertures. Each model consists of two 2-cm-thick glass plates. The top plate is smooth and the bottom plate is roughened on the side facing the top plate. Between the two plates is a slit-like channel representing a single geological fracture. Model A has a roughened plate with a regular roughness. Models B, C and D, with increasing hydraulic apertures, use the same roughened plate with an irregular roughness. We profile the roughness of the roughened plates and study the aperture distribution of the model fractures to characterize the geometry of the model fractures. With local hills (maxima of height) and valleys (minima of height) on the roughened plates, the distribution of aperture of model fractures can be represented as a 2D network of pore bodies and pore throats. In the experiments, we inject pre-generated foam into the model fractures. We study foam behavior after foam flow reaches steady-state. As our models are transparent, we use a high-speed camera to directly visualize and record images of foam in the model fractures. Using ImageJ software, we analyze foam images to quantify the properties of the foam.
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Naturally fractured reservoirs (NFRs) gain much attention worldwide because they are often encountered in aquifer remediation, CO2 sequestration, and hydrocarbon extraction. In hydrocarbon extraction, however, oil recovery by gas injection in NFRs is usually low, because of poor sweep efficiency. During gas injection, the displacement front is unstable. Conformance problems, such as gravity override, viscous fingering, and channeling, take place because the gas has a lighter density and lower viscosity compared to reservoir fluids, and tends to flow preferably through high-permeability zones in heterogeneous reservoirs. In addition, open fractures can have much greater conductivity than the matrix. As a result, gas flows through fractures, leaving much of the matrix unswept. Foam, by adding surfactant solution to gas injection, can effectively mitigate conformance problems by greatly reducing the mobility of gas. During foam flooding in porous media, the displacement front is more stable, and more gas is diverted to unswept zones, hence improving the sweep and increasing oil recovery. Foam can also be created in fractures, where it builds up a viscous pressure gradient and thus diverts the flow of gas into the matrix. As a result, the sweep is improved. In the field, foam pilots have achieved an increase in oil production rate and a reduction in gas/oil ratio. Despite this success, foam application in NFRs is still much less understood than in unfractured porous media. In this dissertation, we aim to expand our understanding of foam in fractures through an experimental approach. To this end, we create four 1-m-long, 15-cm-wide glass model fractures (Models A, B, C and D) with different roughness and hydraulic apertures. Each model consists of two 2-cm-thick glass plates. The top plate is smooth and the bottom plate is roughened on the side facing the top plate. Between the two plates is a slit-like channel representing a single geological fracture. Model A has a roughened plate with a regular roughness. Models B, C and D, with increasing hydraulic apertures, use the same roughened plate with an irregular roughness. We profile the roughness of the roughened plates and study the aperture distribution of the model fractures to characterize the geometry of the model fractures. With local hills (maxima of height) and valleys (minima of height) on the roughened plates, the distribution of aperture of model fractures can be represented as a 2D network of pore bodies and pore throats. In the experiments, we inject pre-generated foam into the model fractures. We study foam behavior after foam flow reaches steady-state. As our models are transparent, we use a high-speed camera to directly visualize and record images of foam in the model fractures. Using ImageJ software, we analyze foam images to quantify the properties of the foam.
In this study, to investigate how gravity affects foam in open vertical fractures, we report foam experiments in three 1-m-long, 15-cm-wide glass-model fractures. Each fracture has a smooth wall and a roughened wall. Between the two walls is a slit-like channel representing a single geological fracture. Three model fractures (Models A, B, and C) share the same roughness and have different hydraulic apertures of 78, 98, and 128 µm, respectively. We conduct foam experiments by horizontal injection in the three model fractures placed horizontally and sideways (i.e., with the model fractures turned on their long side), and in Model A placed vertically with injection upward or downward. Direct imaging of the foam inside the model fracture is facilitated using a high-speed camera. We find that foam reaches local equilibrium (LE; where the rate of bubble generation equals that of bubble destruction) in horizontal-flow experiments in all three model fractures and in vertical-flow experiments in Model A. In fractures with a larger hydraulic aperture, foam is coarser because of less in-situ foam generation. In the vertical-flow experiments in Model A, we find that the properties of the foam are different in upward and downward flow. Compared with downward flooding, upward flooding creates a finer-texture foam, as sections near the inlet of this experiment are in a wetter state, which benefits in-situ foam generation. Moreover, less gas is trapped during upward flooding, as gravitational potential helps overcome the capillarity and moves bubbles upward. In the sideways-flow experiments, gravity segregation takes place. As a result, drier foam propagates along the top of the fractures and wetter foam along the bottom. The segregation is more significant in fractures with a larger hydraulic aperture. At foam quality 0.8, gas saturation is 27.7\ and 19.3\0.8\ respectively. Despite the gravity segregation in all three model fractures, water and gas are not completely segregated. All three model fractures thus represent a capillary transition zone, with greater segregation with increasing aperture. Our results suggest that the propagation of foam in vertical natural fractures meters tall and tens of meters long, with an aperture of hundreds of microns or greater, is problematic. Gravity segregation in foam would weaken its capacity in the field to maintain uniform flow and divert gas in a tall fracture over large distances.
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In this study, to investigate how gravity affects foam in open vertical fractures, we report foam experiments in three 1-m-long, 15-cm-wide glass-model fractures. Each fracture has a smooth wall and a roughened wall. Between the two walls is a slit-like channel representing a single geological fracture. Three model fractures (Models A, B, and C) share the same roughness and have different hydraulic apertures of 78, 98, and 128 µm, respectively. We conduct foam experiments by horizontal injection in the three model fractures placed horizontally and sideways (i.e., with the model fractures turned on their long side), and in Model A placed vertically with injection upward or downward. Direct imaging of the foam inside the model fracture is facilitated using a high-speed camera. We find that foam reaches local equilibrium (LE; where the rate of bubble generation equals that of bubble destruction) in horizontal-flow experiments in all three model fractures and in vertical-flow experiments in Model A. In fractures with a larger hydraulic aperture, foam is coarser because of less in-situ foam generation. In the vertical-flow experiments in Model A, we find that the properties of the foam are different in upward and downward flow. Compared with downward flooding, upward flooding creates a finer-texture foam, as sections near the inlet of this experiment are in a wetter state, which benefits in-situ foam generation. Moreover, less gas is trapped during upward flooding, as gravitational potential helps overcome the capillarity and moves bubbles upward. In the sideways-flow experiments, gravity segregation takes place. As a result, drier foam propagates along the top of the fractures and wetter foam along the bottom. The segregation is more significant in fractures with a larger hydraulic aperture. At foam quality 0.8, gas saturation is 27.7\ and 19.3\0.8\ respectively. Despite the gravity segregation in all three model fractures, water and gas are not completely segregated. All three model fractures thus represent a capillary transition zone, with greater segregation with increasing aperture. Our results suggest that the propagation of foam in vertical natural fractures meters tall and tens of meters long, with an aperture of hundreds of microns or greater, is problematic. Gravity segregation in foam would weaken its capacity in the field to maintain uniform flow and divert gas in a tall fracture over large distances.
Foam coarsening by diffusion (Ostwald ripening) has been well studied in bulk foams. However, it is less well understood in porous media. In particular, the mechanisms that may slow or stop coarsening have not been fully investigated. In this paper, we report an experimental study of foam coarsening in two 1-m-long and 15-cm-wide model fractures. The model fractures, Model 1 and Model 2, are made of glass plates and have different roughness. Model 1 has a regular roughness with hydraulic aperture of 46 μm. Model 2 has an irregular roughness with hydraulic aperture of 78 μm. The two model fractures are transparent, which allows direct investigation of foam in the fractures. We characterize the fracture geometries by studying the aperture distribution in the two model fractures. Both model fractures are then represented by a 2D network of pore bodies and pore throats. To study coarsening, we inject pre-generated foam at different foam qualities (ratio of gas volumetric rate to total rate) into the model fractures. After foam reaches steady-state, we shut the inlet and outlet valves of the fractures for 24 h. Foam coarsens by gas diffusion during this period. We use a high-speed camera to record images of the static foam during coarsening at two fixed locations in the fracture: 19 and 73 cm from the inlet, separately. We then use ImageJ software to process the images to study foam texture and quantify coarsening process. By correlating the aperture histogram of model fractures and water-occupied area fraction, we estimate the local aperture at water-gas interfaces at each specific coarsening time. Using the local aperture, we further estimate the height of lamellae available for gas diffusion at the end of the coarsening experiments. Based on this information, we discuss whether coarsening stops at the end of the coarsening experiments because bubbles are in equilibrium in pressure, or slows nearly to a stop because bubbles lose contact through lamellae. Coarsening studies in bulk and microfluidics assume coarsening slows and stops when lamella curvature is zero. We show in our model fractures that the lack of lamellae in wet foams can also play a part. In addition, we adopt a novel technique to calculate water saturation and capillary pressure of foam in our model fractures. We then explain how these foam properties affect its coarsening behavior.
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Foam coarsening by diffusion (Ostwald ripening) has been well studied in bulk foams. However, it is less well understood in porous media. In particular, the mechanisms that may slow or stop coarsening have not been fully investigated. In this paper, we report an experimental study of foam coarsening in two 1-m-long and 15-cm-wide model fractures. The model fractures, Model 1 and Model 2, are made of glass plates and have different roughness. Model 1 has a regular roughness with hydraulic aperture of 46 μm. Model 2 has an irregular roughness with hydraulic aperture of 78 μm. The two model fractures are transparent, which allows direct investigation of foam in the fractures. We characterize the fracture geometries by studying the aperture distribution in the two model fractures. Both model fractures are then represented by a 2D network of pore bodies and pore throats. To study coarsening, we inject pre-generated foam at different foam qualities (ratio of gas volumetric rate to total rate) into the model fractures. After foam reaches steady-state, we shut the inlet and outlet valves of the fractures for 24 h. Foam coarsens by gas diffusion during this period. We use a high-speed camera to record images of the static foam during coarsening at two fixed locations in the fracture: 19 and 73 cm from the inlet, separately. We then use ImageJ software to process the images to study foam texture and quantify coarsening process. By correlating the aperture histogram of model fractures and water-occupied area fraction, we estimate the local aperture at water-gas interfaces at each specific coarsening time. Using the local aperture, we further estimate the height of lamellae available for gas diffusion at the end of the coarsening experiments. Based on this information, we discuss whether coarsening stops at the end of the coarsening experiments because bubbles are in equilibrium in pressure, or slows nearly to a stop because bubbles lose contact through lamellae. Coarsening studies in bulk and microfluidics assume coarsening slows and stops when lamella curvature is zero. We show in our model fractures that the lack of lamellae in wet foams can also play a part. In addition, we adopt a novel technique to calculate water saturation and capillary pressure of foam in our model fractures. We then explain how these foam properties affect its coarsening behavior.
In enhanced oil recovery, foam can effectively mitigate conformance problems and maintain a stable displacement front, by trapping gas and reducing its relative permeability in situ. In this study, to understand gas trapping in fractures and how it affects foam behavior, we report foam experiments in a 1-m-long glass model fracture with a hydraulic aperture of 80 μm. One wall of the fracture is rough, and the other is smooth. Between the two is a 2D porous medium representing the aperture in a fracture. The fracture model allows direct visualization of foam inside the fracture using a high-speed camera. This study is part of a continuing program to determine how foam behaves as a function of the geometry of the fracture pore space (AlQuaimi and Rossen in Energy & Fuels 33: 68-80, 2018a). We find that local equilibrium of foam (where the rate of bubble generation equals that of bubble destruction) has been achieved within the 1-m model fracture. Foam texture becomes finer, and less gas is trapped as interstitial velocity, and pressure gradient increase. Shear-thinning rheology of foam has also been observed. The fraction of trapped gas is significantly lower in our model (less than 7%) than in 3D geological pore networks. At the extreme, when velocity increases to 7 mm/s, there is no gas trapped inside the fracture. Our experimental results of trapped-gas fraction correlate well with the correlation of AlQuaimi and Rossen (SPE J 23: 788-802, 2018b) for fracture-like porous media. This suggests that the correlation can also be applied to gas trapping in fractures with other geometries.
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In enhanced oil recovery, foam can effectively mitigate conformance problems and maintain a stable displacement front, by trapping gas and reducing its relative permeability in situ. In this study, to understand gas trapping in fractures and how it affects foam behavior, we report foam experiments in a 1-m-long glass model fracture with a hydraulic aperture of 80 μm. One wall of the fracture is rough, and the other is smooth. Between the two is a 2D porous medium representing the aperture in a fracture. The fracture model allows direct visualization of foam inside the fracture using a high-speed camera. This study is part of a continuing program to determine how foam behaves as a function of the geometry of the fracture pore space (AlQuaimi and Rossen in Energy & Fuels 33: 68-80, 2018a). We find that local equilibrium of foam (where the rate of bubble generation equals that of bubble destruction) has been achieved within the 1-m model fracture. Foam texture becomes finer, and less gas is trapped as interstitial velocity, and pressure gradient increase. Shear-thinning rheology of foam has also been observed. The fraction of trapped gas is significantly lower in our model (less than 7%) than in 3D geological pore networks. At the extreme, when velocity increases to 7 mm/s, there is no gas trapped inside the fracture. Our experimental results of trapped-gas fraction correlate well with the correlation of AlQuaimi and Rossen (SPE J 23: 788-802, 2018b) for fracture-like porous media. This suggests that the correlation can also be applied to gas trapping in fractures with other geometries.
By trapping gas, foam can improve the sweep efficiency in enhanced oil recovery. In this study, to understand gas trapping in fractures, we have conducted experiments in a model fracture with a hydraulic aperture of 80 μm. One wall of the fracture is rough, and the other wall is smooth. The fracture is made of two glass plates and the direct visualization of foam flow inside the fracture is facilitated using a high-speed camera. ImageJ has been used to perform image analysis and quantify the properties of the foam. We find that pre-generated foam has been further refined inside the model. Foam flow reaches local equilibrium, where the rate of bubble generation equals that of bubble destruction, within the model. Foam texture becomes finer and less gas is trapped as the interstitial velocity and pressure gradient increase. Shear-thinning rheology of foam has also been observed. The behavior of gas trapping in our model fracture is different from that in other geological porous media. The fraction of trapped gas is much lower (less than 7%). At the extreme, when velocity increases to 6.8 mm/s (pressure gradient to 1.8 bar/m), all the foam bubbles are flowing and there is no gas trapped inside the fracture.
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By trapping gas, foam can improve the sweep efficiency in enhanced oil recovery. In this study, to understand gas trapping in fractures, we have conducted experiments in a model fracture with a hydraulic aperture of 80 μm. One wall of the fracture is rough, and the other wall is smooth. The fracture is made of two glass plates and the direct visualization of foam flow inside the fracture is facilitated using a high-speed camera. ImageJ has been used to perform image analysis and quantify the properties of the foam. We find that pre-generated foam has been further refined inside the model. Foam flow reaches local equilibrium, where the rate of bubble generation equals that of bubble destruction, within the model. Foam texture becomes finer and less gas is trapped as the interstitial velocity and pressure gradient increase. Shear-thinning rheology of foam has also been observed. The behavior of gas trapping in our model fracture is different from that in other geological porous media. The fraction of trapped gas is much lower (less than 7%). At the extreme, when velocity increases to 6.8 mm/s (pressure gradient to 1.8 bar/m), all the foam bubbles are flowing and there is no gas trapped inside the fracture.
In this study, to investigate how gravity affects foam in fractures, we carry out seven sets of foam-scan experiments on three glass model fractures (model A, model B and model C) with a hydraulic aperture of 78, 98 and 128 microns respectively. We compare the behaviour of foam in the models placed horizontally and vertically. We find that stable foam is created and reaches local equilibrium in all horizontal-flow experiments in 3 models. Foam gets weaker as the hydraulic aperture of fracture becomes larger. In sideways flow experiments, the effect of gravity on foam stability is less in model A. As the hydraulic aperture increases, the effect of gravity is more pronounced. Due to gravity, drier and coarser foam propagates at the top of the fractures, wetter and finer foam along the bottom. Foam is stable during the sideways flow experiments in model A and B, at all foam qualities. In model C, foam breakage alternates with re-generation near the top at foam qualities larger than 0.94. It is concluded that the application of foam in vertical natural fractures (meters tall and tens of meter long) with an aperture up to hundreds of microns is problematic.
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In this study, to investigate how gravity affects foam in fractures, we carry out seven sets of foam-scan experiments on three glass model fractures (model A, model B and model C) with a hydraulic aperture of 78, 98 and 128 microns respectively. We compare the behaviour of foam in the models placed horizontally and vertically. We find that stable foam is created and reaches local equilibrium in all horizontal-flow experiments in 3 models. Foam gets weaker as the hydraulic aperture of fracture becomes larger. In sideways flow experiments, the effect of gravity on foam stability is less in model A. As the hydraulic aperture increases, the effect of gravity is more pronounced. Due to gravity, drier and coarser foam propagates at the top of the fractures, wetter and finer foam along the bottom. Foam is stable during the sideways flow experiments in model A and B, at all foam qualities. In model C, foam breakage alternates with re-generation near the top at foam qualities larger than 0.94. It is concluded that the application of foam in vertical natural fractures (meters tall and tens of meter long) with an aperture up to hundreds of microns is problematic.
A microfluidic device is one of the most stimulating research tools for foam studies, because it provides the opportunity to visualize foam behaviour directly. In this study, we employ a model similar to microfluidics, directly applicable to flow in geological fractures. The 1-meter-long model represents a fracture channel with one roughened and one smooth wall. It has a width of 15 cm and a hydraulic aperture of 128 µm. The model is made of glass plates and enables direct investigation of foam flow (Figure 1) through the channel using a high-speed camera. We conducted a series of foam experiments in the model. Local equilibrium between processes of foam creation and destruction is reached within our long model. We study the dynamics of gas trapping at different velocities and gas fractional flows. We observe that velocity affects the fraction of gas which is trapped in the model at low foam qualities. Gas trapping lessens and foam mobility increases as superficial velocity increases. This contributes to the shear-thinning mobility of the foam. At high foam qualities, the relation between trapped gas and foam mobility is weaker: gas trapping is insignificant and has little effect on foam mobility. When gas fractional flow increases at high foam qualities, flow alternates between slugs of gas and foam.
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A microfluidic device is one of the most stimulating research tools for foam studies, because it provides the opportunity to visualize foam behaviour directly. In this study, we employ a model similar to microfluidics, directly applicable to flow in geological fractures. The 1-meter-long model represents a fracture channel with one roughened and one smooth wall. It has a width of 15 cm and a hydraulic aperture of 128 µm. The model is made of glass plates and enables direct investigation of foam flow (Figure 1) through the channel using a high-speed camera. We conducted a series of foam experiments in the model. Local equilibrium between processes of foam creation and destruction is reached within our long model. We study the dynamics of gas trapping at different velocities and gas fractional flows. We observe that velocity affects the fraction of gas which is trapped in the model at low foam qualities. Gas trapping lessens and foam mobility increases as superficial velocity increases. This contributes to the shear-thinning mobility of the foam. At high foam qualities, the relation between trapped gas and foam mobility is weaker: gas trapping is insignificant and has little effect on foam mobility. When gas fractional flow increases at high foam qualities, flow alternates between slugs of gas and foam.
Gas injection often suffers from the poor sweep efficiency because of conformance problems, including gravity override, viscous fingering and channelling, as gas has a lighter density and a lower viscosity compared to in-situ fluids. Foam, by encapsulating the gas into separate bubbles in surfactant-contained liquid thin films (lamella), can effectively solve the conformance problems and hence improve the sweep.
Strong foam can reduce gas mobility by a factor of hundreds, by trapping gas and reducing its relative permeability in situ[1]. To efficiently improve the sweep, foam needs to propagate and maintain its strength at locations further away from the injection well. Foam trapping and propagation are highly dependent on porous media geometry, injection rate, foam quality, etc.
Microfluidic system, a medium integrating flow channels of manipulated structures on the order of tens to hundreds of microns, have been increasingly attractive to oil and gas, chemical and pharmaceutical industries[2]. Microfluidics are also becoming one of the most stimulating research field in foam EOR, because it provides the opportunities to visualize foam behaviour directly, such as foam generation, propagation and foam coarsening[3], etc.
We employ a model similar to microfluidics, directly applicable to flow in geological fractures. The 1-meter-long model represents a fracture channel with one roughened and one smooth wall. It has a width of 15 centimeters and a hydraulic aperture of 128 µm. The model is made of glass plates, therefore enabling direct investigation of foam behaviour through the channel using a high-speed camera. Since roughened glass is available with a range of roughness scales[4], one can relate foam behaviour to the roughness pattern in the channel.
We conduct a series of foam experiments in the model. Local equilibrium of foam (i.e. the rate of bubble generation equals to that of bubble destruction) is reached within our long model. We study the dynamics of gas trapping at different velocities and gas fractional flows.
We observe that velocity affects the fraction of gas which is trapped in the model at low foam qualities. Gas trapping decreases and foam mobility increases as superficial velocity increases. At high foam qualities, the relation between trapped gas and foam mobility is weaker. Gas trapping is insignificant and has little effect on foam mobility. When gas fractional flow increases at high foam qualities, flow alternates between slugs of gas and foam.
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Gas injection often suffers from the poor sweep efficiency because of conformance problems, including gravity override, viscous fingering and channelling, as gas has a lighter density and a lower viscosity compared to in-situ fluids. Foam, by encapsulating the gas into separate bubbles in surfactant-contained liquid thin films (lamella), can effectively solve the conformance problems and hence improve the sweep.
Strong foam can reduce gas mobility by a factor of hundreds, by trapping gas and reducing its relative permeability in situ[1]. To efficiently improve the sweep, foam needs to propagate and maintain its strength at locations further away from the injection well. Foam trapping and propagation are highly dependent on porous media geometry, injection rate, foam quality, etc.
Microfluidic system, a medium integrating flow channels of manipulated structures on the order of tens to hundreds of microns, have been increasingly attractive to oil and gas, chemical and pharmaceutical industries[2]. Microfluidics are also becoming one of the most stimulating research field in foam EOR, because it provides the opportunities to visualize foam behaviour directly, such as foam generation, propagation and foam coarsening[3], etc.
We employ a model similar to microfluidics, directly applicable to flow in geological fractures. The 1-meter-long model represents a fracture channel with one roughened and one smooth wall. It has a width of 15 centimeters and a hydraulic aperture of 128 µm. The model is made of glass plates, therefore enabling direct investigation of foam behaviour through the channel using a high-speed camera. Since roughened glass is available with a range of roughness scales[4], one can relate foam behaviour to the roughness pattern in the channel.
We conduct a series of foam experiments in the model. Local equilibrium of foam (i.e. the rate of bubble generation equals to that of bubble destruction) is reached within our long model. We study the dynamics of gas trapping at different velocities and gas fractional flows.
We observe that velocity affects the fraction of gas which is trapped in the model at low foam qualities. Gas trapping decreases and foam mobility increases as superficial velocity increases. At high foam qualities, the relation between trapped gas and foam mobility is weaker. Gas trapping is insignificant and has little effect on foam mobility. When gas fractional flow increases at high foam qualities, flow alternates between slugs of gas and foam.
Gas-injection EOR processes have poor sweep efficiency due to conformance problems including channelling, gravity override and fingering. In naturally fractured reservoirs, sweep efficiency is further jeopardized, because gas breaks through fractures first, leaving most oil behind in the matrix. Strong foam can be created in fractures[1][2], thus diverting the flow of gas into matrix and hence increasing the oil recovery[3]. In the field, natural fractures are usually vertically oriented, because the least principle stress is in horizontal direction in most formations. Foam performance in fractured reservoirs is not only affected by fracture roughness, aperture, etc., but also by gravity.
In this study, we investigate how gravity affect foam in fractures. To this end, we have conducted several sets of foam-scan experiments (i.e., a set of constant-total-velocity experiments each with a different gas fractional flow) on three glass model fractures (model A, model B and model C) with hydraulic aperture of 78, 99 and 128 µm respectively.
The models have the same dimensions of 1 m x 0.15 m (L x W) and the same fracture roughness pattern. The transparency of glass models allows a direct investigation of foam texture inside the fracture using a high-speed camera. All experiments have been carried out at 20°C and 1 atm. Nitrogen is the gas phase, and surfactant solution is 1 wt % AOS C14-16.
Experiments were carried out on all three models by placing the model either horizontally or on its side. Stable foam was created and reached local equilibrium in all horizontal-flow experiments, i.e., the rate of foam lamella creation was equal to the rate of destruction. The roughened fracture surface provided sufficient generation sites to re-create foam bubbles in sections further from the entry, hence maintaining a stable foam.
In the sideways flow experiment, the effect of gravity on foam stability was not significant when fracture aperture was small (model A). As hydraulic aperture increased (model B and model C), the effect of gravity was more pronounced. Drier foam propagated along the top part of the fractures and wetter foam along the bottom. Gas saturation was 23% greater at the top than the bottom for model B, and 34% for model C. Foam was still stable during the sideways flow experiments in model B. However, foam breakage alternated with re-generation near the top in model C.
We conclude that the application of foam in vertical natural fractures (meters tall and tens of meter long) with a aperture of hundreds of microns is problematic. The gravity segregation of phases for this foam would disable its capacity to divert gas flow from a tall fracture like our model into the matrix. As a result, there will be a gas-rich regime at the top of the fracture and a liquid-rich regime at the bottom. The regimes segregate more as the aperture increases.
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Gas-injection EOR processes have poor sweep efficiency due to conformance problems including channelling, gravity override and fingering. In naturally fractured reservoirs, sweep efficiency is further jeopardized, because gas breaks through fractures first, leaving most oil behind in the matrix. Strong foam can be created in fractures[1][2], thus diverting the flow of gas into matrix and hence increasing the oil recovery[3]. In the field, natural fractures are usually vertically oriented, because the least principle stress is in horizontal direction in most formations. Foam performance in fractured reservoirs is not only affected by fracture roughness, aperture, etc., but also by gravity.
In this study, we investigate how gravity affect foam in fractures. To this end, we have conducted several sets of foam-scan experiments (i.e., a set of constant-total-velocity experiments each with a different gas fractional flow) on three glass model fractures (model A, model B and model C) with hydraulic aperture of 78, 99 and 128 µm respectively.
The models have the same dimensions of 1 m x 0.15 m (L x W) and the same fracture roughness pattern. The transparency of glass models allows a direct investigation of foam texture inside the fracture using a high-speed camera. All experiments have been carried out at 20°C and 1 atm. Nitrogen is the gas phase, and surfactant solution is 1 wt % AOS C14-16.
Experiments were carried out on all three models by placing the model either horizontally or on its side. Stable foam was created and reached local equilibrium in all horizontal-flow experiments, i.e., the rate of foam lamella creation was equal to the rate of destruction. The roughened fracture surface provided sufficient generation sites to re-create foam bubbles in sections further from the entry, hence maintaining a stable foam.
In the sideways flow experiment, the effect of gravity on foam stability was not significant when fracture aperture was small (model A). As hydraulic aperture increased (model B and model C), the effect of gravity was more pronounced. Drier foam propagated along the top part of the fractures and wetter foam along the bottom. Gas saturation was 23% greater at the top than the bottom for model B, and 34% for model C. Foam was still stable during the sideways flow experiments in model B. However, foam breakage alternated with re-generation near the top in model C.
We conclude that the application of foam in vertical natural fractures (meters tall and tens of meter long) with a aperture of hundreds of microns is problematic. The gravity segregation of phases for this foam would disable its capacity to divert gas flow from a tall fracture like our model into the matrix. As a result, there will be a gas-rich regime at the top of the fracture and a liquid-rich regime at the bottom. The regimes segregate more as the aperture increases.