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M S A Perera - One of the best experts on this subject based on the ideXlab platform.
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the effect of saturation conditions on fracture performance of different soundless cracking demolition agents scdas in geological Reservoir Rock formations
Journal of Natural Gas Science and Engineering, 2019Co-Authors: V R S De Silva, M S A Perera, P G RanjithAbstract:Abstract Fracture stimulation using soundless cracking demolition agents (SCDAs) is a potential alternative technique to induce high-density fractures in sedimentary Reservoir-Rock as an auxiliary technique to improve the efficiency of enhanced oil and gas recovery efficiencies. However, to date, its application has been limited to fracture stimulation in dry Rock masses. Therefore, using modified SCDAs, which can be used for underwater Rock fracturing, a series of experiments was conducted to investigate the fracturing performance of SCDAs in saturated Rock masses. 18 coarse-grained sandstone specimens were saturated in water, oil, and NaCl brine and fractured using three different SCDA types: a standard SCDA (S1), and two modified for underwater application (S2) and accelerated reaction rate (S3). Then, the fractured samples were scanned in the Australian Synchrotron, and the fractures were quantified using Avizo 9.0.1. The fracture initiation time and the total fracture network length and volume were found to be dependent on the saturated pore fluid of Rock. Water saturation of samples increased the fracture initiation time by 16.5%, 24.1% and 13.68% for S1, S2, and S3 type SCDAs respectively and reduced the fracturing potential of SCDA by 59.5%, 32.49% and 66.67% compared to dry samples. This reduction was less apparent in oil-saturated samples as the high pore fluid viscosity of oil-saturated samples aid fracturing, which is explained by the Poiseuille equation. Increasing salinity in the saturation fluid from 0% to 12.5% was favourable for the fracturing efficiency of SCDAs because of the formation of CaCl2 in the pore fluid, which accelerates the reaction of SCDA. Fracture orientation also changed depending on the saturation fluid, which was again governed by the variation in reaction rate in SCDAs under different saturation conditions.
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stress state and stress path evaluation to address uncertainties in Reservoir Rock failure in co2 sequestration in deep saline aquifers an experimental study of the hawkesbury sandstone formation
Journal of CO 2 Utilization, 2018Co-Authors: T D Rathnaweera, W A M Wanniarachchi, M S A Perera, P G Ranjith, K M A S BandaraAbstract:Abstract Injecting CO2 into aquifer pore fluid (high salinity brine) in deep saline aquifers during the sequestration process causes the chemico-mineral structure to be altered through complex chemically-coupled mechanical deformations. This is as yet poorly understood in the field. The authors conducted a series of tri-axial strength tests on Hawkesbury sandstone under in-situ stress and temperature conditions to characterise the behaviour of Reservoir Rock upon exposure to super-critical CO2 (ScCO2) to determine this chemically-coupled mechanical behaviour. According to the findings, injection of CO2 into a brine-saturated Reservoir Rock mass may cause a considerable strength reduction, probably due to the Rock’s mineralogical alteration-induced mechanical weakening of grain contacts. This was confirmed by SEM analysis, according to which the mineral dissolution process upon exposure to ScCO2 is significant, and considerable quartz and calcite dissolution were noticed in the tested samples. Importantly, this Rock mineral dissolution may alter the Reservoir’s natural pore geometry. This eventually affects the effective stress patterns acting on the Rock matrix. In addition, the slip tendency of brine+CO2-reacted Reservoir Rock is increased with increasing injection pressure, revealing the fate of the resulting pore pressure-dominant effective stress field through the CO2 injection process. The results were then incorporated in the effective stress field model. This model can be used to predict the possibility of mechanical failure of Reservoir Rock upon CO2 injection into saline aquifers.
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investigation of depth and injection pressure effects on breakdown pressure and fracture permeability of shale Reservoirs an experimental study
Applied Sciences, 2017Co-Authors: W A M Wanniarachchi, Ranjith Pathegama Gamage, M S A Perera, T D Rathnaweera, Mingzhong Gao, Eswaran PadmanabhanAbstract:The aim of this study was to identify the influence of Reservoir depth on Reservoir Rock mass breakdown pressure and the influence of Reservoir depth and injecting fluid pressure on the flow ability of Reservoirs before and after the hydraulic fracturing process. A series of fracturing tests was conducted under a range of confining pressures (1, 3, 5 and 7 MPa) to simulate various depths. In addition, permeability tests were conducted on intact and fractured samples under 1 and 7 MPa confining pressures to determine the flow characteristic variations upon fracturing of the Reservoir, depending on the Reservoir depth and injecting fluid pressure. N2 permeability was tested under a series of confining pressures (5, 10, 15, 20 and 25 MPa) and injection pressures (1–10 MPa). According to the results, shale Reservoir flow ability for gas movement may reduce with increasing injection pressure and Reservoir depth, due to the Klinkenberg phenomenon and pore structure shrinkage, respectively. The breakdown pressure of the Reservoir Rock linearly increases with increasing Reservoir depth (confining pressure). Interestingly, 81% permeability reduction was observed in the fractured Rock mass due to high (25 MPa) confinement, which shows the importance of proppants in the fracturing process.
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development of a laboratory scale numerical model to simulate the mechanical behaviour of deep saline Reservoir Rocks under varying salinity conditions in uniaxial and triaxial test environments
Measurement, 2017Co-Authors: T D Rathnaweera, M S A Perera, P G Ranjith, V R S De SilvaAbstract:Abstract The maintenance of the long-term mechanical stability of the Reservoir Rock mass is essential in CO 2 sequestration in deep saline aquifers. However, it cannot be confirmed without predicting the worst-case scenarios in saline aquifers, including high salinity conditions and the complexities caused by surrounding factors such as Reservoir depth. Laboratory experiments to identify all such situations are difficult due to the advanced facilities required, and the associated cost and time. Therefore, numerical models play an important role in extending laboratory measurements for such complex and extreme situations. Although numerous numerical studies have been performed to date on field-scale conditions in saline aquifers, less consideration has been given to simulating laboratory data, which is important for up-scaling the data to field conditions. This study therefore aims to develop a laboratory-scale numerical model to simulate the mechanical behaviour of brine-saturated Reservoir Rock under triaxial stress laboratory conditions. The model validation was performed by measuring uniaxial and triaxial laboratory test data under 10–25 MPa confining pressures and the model was then used to investigate the influence of pore fluid salinity percentage on Reservoir Rock strength by considering various possible salinity levels (5%, 10%, 15%, 20%, 25% and 30% NaCl) and the influence of depth using a range of confining pressures from 10 to 100 MPa. The proposed numerical model based on the stiffness degradation mechanism of Reservoir Rock can accurately simulate salinity-dependent stress-strain behaviour under any stress environment (uniaxial/triaxial). According to the model, both pore fluid salinity and confining stress add additional strength to the Reservoir Rock mass due to NaCl crystallization and pore shrinkage. Importantly, the model clearly shows a reduction of the effect of pore fluid salinity on Reservoir Rock strength characteristics with increasing Reservoir depth or confinement, mostly due to the more significant effective stress at such extreme depths. This provides an important finding on CO 2 sequestration in saline aquifers: salinity-dependent strength alteration is not very important for extremely deep aquifers compared to shallow aquifers. Although this model has the capability to simulate the failure of Reservoir Rock under extreme pressure conditions, the simulation results show a small fluctuation near the post-peak stage due to the complexity of the damage mechanism caused by strain localization.
Martin J Blunt - One of the best experts on this subject based on the ideXlab platform.
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pore scale imaging and characterization of hydrocarbon Reservoir Rock wettability at subsurface conditions using x ray microtomography
Journal of Visualized Experiments, 2018Co-Authors: Amer M Alhammadi, Ahmed Alratrout, Branko Bijeljic, Martin J BluntAbstract:In situ wettability measurements in hydrocarbon Reservoir Rocks have only been possible recently. The purpose of this work is to present a protocol to characterize the complex wetting conditions of hydrocarbon Reservoir Rock using pore-scale three-dimensional X-ray imaging at subsurface conditions. In this work, heterogeneous carbonate Reservoir Rocks, extracted from a very large producing oil field, have been used to demonstrate the protocol. The Rocks are saturated with brine and oil and aged over three weeks at subsurface conditions to replicate the wettability conditions that typically exist in hydrocarbon Reservoirs (known as mixed-wettability). After the brine injection, high-resolution three-dimensional images (2 µm/voxel) are acquired and then processed and segmented. To calculate the distribution of the contact angle, which defines the wettability, the following steps are performed. First, fluid-fluid and fluid-Rock surfaces are meshed. The surfaces are smoothed to remove voxel artefacts, and in situ contact angles are measured at the three-phase contact line throughout the whole image. The main advantage of this method is its ability to characterize in situ wettability accounting for pore-scale Rock properties, such as Rock surface roughness, Rock chemical composition, and pore size. The in situ wettability is determined rapidly at hundreds of thousands of points. The method is limited by the segmentation accuracy and X-ray image resolution. This protocol could be used to characterize the wettability of other complex Rocks saturated with different fluids and at different conditions for a variety of applications. For example, it could help in determining the optimal wettability that could yield an extra oil recovery (i.e., designing brine salinity accordingly to obtain higher oil recovery) and to find the most efficient wetting conditions to trap more CO2 in subsurface formations.
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in situ characterization of mixed wettability in a Reservoir Rock at subsurface conditions
Scientific Reports, 2017Co-Authors: Amer M Alhammadi, Ahmed Alratrout, Branko Bijeljic, Kamaljit Singh, Martin J BluntAbstract:We used X-ray micro-tomography to image the in situ wettability, the distribution of contact angles, at the pore scale in calcite cores from a producing hydrocarbon Reservoir at subsurface conditions. The contact angle was measured at hundreds of thousands of points for three samples after twenty pore volumes of brine flooding.We found a wide range of contact angles with values both above and below 90°. The hypothesized cause of wettability alteration by an adsorbed organic layer on surfaces contacted by crude oil after primary drainage was observed with Scanning Electron Microscopy (SEM) and identified using Energy Dispersive X-ray (EDX) analysis. However, not all oil-filled pores were altered towards oil-wet conditions, which suggests that water in surface roughness, or in adjacent micro-porosity, can protect the surface from a strong wettability alteration. The lowest oil recovery was observed for the most oil-wet sample, where the oil remained connected in thin sheet-like layers in the narrower regions of the pore space. The highest recovery was seen for the sample with an average contact angle close to 90°, with an intermediate recovery in a more water-wet system, where the oil was trapped in ganglia in the larger regions of the pore space.
Huang Zeng - One of the best experts on this subject based on the ideXlab platform.
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identification of organic species with double sided tape characteristics on the surface of carbonate Reservoir Rock
Fuel, 2021Co-Authors: Nathalia Tessarolo, Nan Wang, Chrissie Wicking, Ian Ralph Collins, Kevin John Webb, John William Couves, Jonathan Crouch, Colm Durkan, Huang ZengAbstract:Abstract Carbonate Reservoir Rocks are normally mixed-wet or oil-wet, leading to low oil recovery efficiency using water-based oil recovery methods. It is critical to understand the molecular composition of the organic material coating the surface of carbonate Reservoir Rock in order to design better enhanced oil recovery (EOR) methods. Herein, we extracted organic compounds from a carbonate Reservoir Rock and characterized their composition using high resolution mass spectrometry (HRMS). In contrast to conventional interpretation that the mixed-wet or oil-wet nature of carbonate Reservoir Rocks arises from the adsorption of carboxylic acids, our results demonstrated that the organic species strongly bound to carbonate Reservoir Rock surface are dominated by N-containing species, including a group of “sticky molecules”. Each of these molecules can form multiple hydrogen-bonds, therefore they might act as a “double-sided tape” which binds crude oil strongly to the carbonate Rock surface. Furthermore, we applied atomic force microscopy (AFM) techniques to a model mineral surface with regions of positive change and negative charge which was contacted with the crude oil produced from the formation where the Rock was sampled. It was found that only the organic molecules with positive charge in the oil were adsorbed onto the mineral. This supports HRMS results which suggest that the organic materials strongly bound to the carbonate Reservoir Rock surface are dominated by basic N-containing molecules. Overall, these findings suggest that, beside fatty acids, these “sticky molecules” might also play an important role in controlling the wetting state of carbonate Reservoir Rock.
Lamia Goual - One of the best experts on this subject based on the ideXlab platform.
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the effects of so2 contamination brine salinity pressure and temperature on dynamic contact angles and interfacial tension of supercritical co2 brine quartz systems
International Journal of Greenhouse Gas Control, 2014Co-Authors: Soheil Saraji, Mohammad Piri, Lamia GoualAbstract:Abstract The successful implementation of geologic CO2 sequestration schemes in deep saline aquifers requires storage sites with minimum risk of CO2 leakage through the capRock and maximum storage capacity in the Reservoir Rock. Some of the essential parameters that affect the effectiveness of a storage scheme are the density of CO2, the interfacial tension between CO2-rich and aqueous phases, and the wettability of Reservoir Rock and capRock in contact with these fluids at Reservoir conditions ( Tokunaga and Wan, 2013 ). In this study, densities, interfacial tensions, and dynamic contact angles of CO2/brine/quartz systems at high temperatures and pressures were simultaneously measured using the Axisymmetric Drop Shape Analysis with no-Apex (ADSA-NA) method. Measurements were performed at pressures (2000–4000 psig), temperatures (50–100 °C), and brine salinities (0.2–5 M) relevant to carbon sequestration in deep saline aquifers. These experimental conditions had not been investigated in the past. Additionally, the effect of SO2 as a co-contaminant (0–6 wt%) was investigated on these parameters for the first time. Contact angle hysteresis was also examined and the possible implications of the results on different CO2 trapping mechanisms were discussed.
P G Ranjith - One of the best experts on this subject based on the ideXlab platform.
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the effect of saturation conditions on fracture performance of different soundless cracking demolition agents scdas in geological Reservoir Rock formations
Journal of Natural Gas Science and Engineering, 2019Co-Authors: V R S De Silva, M S A Perera, P G RanjithAbstract:Abstract Fracture stimulation using soundless cracking demolition agents (SCDAs) is a potential alternative technique to induce high-density fractures in sedimentary Reservoir-Rock as an auxiliary technique to improve the efficiency of enhanced oil and gas recovery efficiencies. However, to date, its application has been limited to fracture stimulation in dry Rock masses. Therefore, using modified SCDAs, which can be used for underwater Rock fracturing, a series of experiments was conducted to investigate the fracturing performance of SCDAs in saturated Rock masses. 18 coarse-grained sandstone specimens were saturated in water, oil, and NaCl brine and fractured using three different SCDA types: a standard SCDA (S1), and two modified for underwater application (S2) and accelerated reaction rate (S3). Then, the fractured samples were scanned in the Australian Synchrotron, and the fractures were quantified using Avizo 9.0.1. The fracture initiation time and the total fracture network length and volume were found to be dependent on the saturated pore fluid of Rock. Water saturation of samples increased the fracture initiation time by 16.5%, 24.1% and 13.68% for S1, S2, and S3 type SCDAs respectively and reduced the fracturing potential of SCDA by 59.5%, 32.49% and 66.67% compared to dry samples. This reduction was less apparent in oil-saturated samples as the high pore fluid viscosity of oil-saturated samples aid fracturing, which is explained by the Poiseuille equation. Increasing salinity in the saturation fluid from 0% to 12.5% was favourable for the fracturing efficiency of SCDAs because of the formation of CaCl2 in the pore fluid, which accelerates the reaction of SCDA. Fracture orientation also changed depending on the saturation fluid, which was again governed by the variation in reaction rate in SCDAs under different saturation conditions.
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stress state and stress path evaluation to address uncertainties in Reservoir Rock failure in co2 sequestration in deep saline aquifers an experimental study of the hawkesbury sandstone formation
Journal of CO 2 Utilization, 2018Co-Authors: T D Rathnaweera, W A M Wanniarachchi, M S A Perera, P G Ranjith, K M A S BandaraAbstract:Abstract Injecting CO2 into aquifer pore fluid (high salinity brine) in deep saline aquifers during the sequestration process causes the chemico-mineral structure to be altered through complex chemically-coupled mechanical deformations. This is as yet poorly understood in the field. The authors conducted a series of tri-axial strength tests on Hawkesbury sandstone under in-situ stress and temperature conditions to characterise the behaviour of Reservoir Rock upon exposure to super-critical CO2 (ScCO2) to determine this chemically-coupled mechanical behaviour. According to the findings, injection of CO2 into a brine-saturated Reservoir Rock mass may cause a considerable strength reduction, probably due to the Rock’s mineralogical alteration-induced mechanical weakening of grain contacts. This was confirmed by SEM analysis, according to which the mineral dissolution process upon exposure to ScCO2 is significant, and considerable quartz and calcite dissolution were noticed in the tested samples. Importantly, this Rock mineral dissolution may alter the Reservoir’s natural pore geometry. This eventually affects the effective stress patterns acting on the Rock matrix. In addition, the slip tendency of brine+CO2-reacted Reservoir Rock is increased with increasing injection pressure, revealing the fate of the resulting pore pressure-dominant effective stress field through the CO2 injection process. The results were then incorporated in the effective stress field model. This model can be used to predict the possibility of mechanical failure of Reservoir Rock upon CO2 injection into saline aquifers.
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development of a laboratory scale numerical model to simulate the mechanical behaviour of deep saline Reservoir Rocks under varying salinity conditions in uniaxial and triaxial test environments
Measurement, 2017Co-Authors: T D Rathnaweera, M S A Perera, P G Ranjith, V R S De SilvaAbstract:Abstract The maintenance of the long-term mechanical stability of the Reservoir Rock mass is essential in CO 2 sequestration in deep saline aquifers. However, it cannot be confirmed without predicting the worst-case scenarios in saline aquifers, including high salinity conditions and the complexities caused by surrounding factors such as Reservoir depth. Laboratory experiments to identify all such situations are difficult due to the advanced facilities required, and the associated cost and time. Therefore, numerical models play an important role in extending laboratory measurements for such complex and extreme situations. Although numerous numerical studies have been performed to date on field-scale conditions in saline aquifers, less consideration has been given to simulating laboratory data, which is important for up-scaling the data to field conditions. This study therefore aims to develop a laboratory-scale numerical model to simulate the mechanical behaviour of brine-saturated Reservoir Rock under triaxial stress laboratory conditions. The model validation was performed by measuring uniaxial and triaxial laboratory test data under 10–25 MPa confining pressures and the model was then used to investigate the influence of pore fluid salinity percentage on Reservoir Rock strength by considering various possible salinity levels (5%, 10%, 15%, 20%, 25% and 30% NaCl) and the influence of depth using a range of confining pressures from 10 to 100 MPa. The proposed numerical model based on the stiffness degradation mechanism of Reservoir Rock can accurately simulate salinity-dependent stress-strain behaviour under any stress environment (uniaxial/triaxial). According to the model, both pore fluid salinity and confining stress add additional strength to the Reservoir Rock mass due to NaCl crystallization and pore shrinkage. Importantly, the model clearly shows a reduction of the effect of pore fluid salinity on Reservoir Rock strength characteristics with increasing Reservoir depth or confinement, mostly due to the more significant effective stress at such extreme depths. This provides an important finding on CO 2 sequestration in saline aquifers: salinity-dependent strength alteration is not very important for extremely deep aquifers compared to shallow aquifers. Although this model has the capability to simulate the failure of Reservoir Rock under extreme pressure conditions, the simulation results show a small fluctuation near the post-peak stage due to the complexity of the damage mechanism caused by strain localization.
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mechanical behaviour of Reservoir Rock under brine saturation
Rock Mechanics and Rock Engineering, 2013Co-Authors: Richa Shukla, P G Ranjith, S K Choi, Asadul Haque, Mohan Yellishetty, Li HongAbstract:Acoustic emissions (AE) and stress–strain curve analysis are well accepted ways of analysing crack propagation and monitoring the various failure stages (such as crack closure, crack initiation level during Rock failure under compression) of Rocks and Rock-like materials. This paper presents details and results of experimental investigations conducted for characterizing the brittle failure processes induced in a Rock due to monocyclic uniaxial compression on loading of two types of sandstone core samples saturated in NaCl brines of varying concentration (0, 2, 5, 10 and 15 % NaCl by weight). The two types of sandstone samples were saturated under vacuum for more than 45 days with the respective pore fluid to allow them to interact with the Rocks. It was observed that the uniaxial compressive strength and stress–strain behaviour of the Rock specimens changed with increasing NaCl concentration in the saturating fluid. The acoustic emission patterns also varied considerably for increasing ionic strength of the saturating brines. These observations can be attributed to the deposition of NaCl crystals in the Rock’s pore spaces as well some minor geo-chemical interactions between the Rock minerals and the brine. The AE pattern variations could also be partly related to the higher conductivity of the ionic strength of the high-NaCl concentration brine as it is able to transfer more acoustic energy from the cracks to the AE sensors.
