CO2-brine-rock interactions: The effect of impurities on grain size distribution and reservoir permeability (original) (raw)
Energy Procedia, 2014
We measured the change in permeability of two selected sandstones (Berea, Fonteinebleau) due to injection of CO 2saturated ("live") brine, unsaturated ("dead") brine or supercritical (sc) CO 2 at reservoir conditions. We found that the permeability did not significantly change in a clean sandstone consisting of pure quartz (Fonteinemebleau) due to live or dead brine injection, although permeability changed due to scCO 2 injection by 23%. The permeability in the Berea sandstone, however, changed due to live or dead brine injection, by up to 35%; this permeability reduction in Berea sandstone was likely caused by fines release and subsequent pore throat plugging as the damage was more significant at higher injection rates. We expect that this phenomenon -i.e. rock permeability reduction due to CO 2 injection into the formation -can have a significant and detrimental influence on CO 2 injectivity, which would be reduced accordingly.
Energy Procedia, 2009
Experimental studies of both drainage and imbibition displacements are needed to improve our fundamental understanding of multi-phase flow and trapping in CO 2-brine systems and effectively take advantage of the large storage capacity of saline aquifers. Very few relative permeability measurements have been made and even fewer with in situ saturation measurements. Two new sets of steady state relative permeability measurements have been made in two different rock samples, and over a range of injection flow rates. These studies show that multi-phase brine displacement efficiency is strongly affected by the heterogeneity of the core. Moreover, we observe that, at any given fractional flow, different flow rates result in different CO 2 saturations. Similarly, different flow rates lead to different relative permeability curves. Numerical simulations of two phase displacement are performed on one sample, and at one fractional flow of CO 2. Numerical simulations demonstrate that some of the features of the saturation distributions can be qualitatively replicated. However, improvements in the correlations between porosity, saturation and capillary pressure will be needed to replicate the saturation distributions measured in the experiments.
Geochemical effects of impurities in CO 2 on a sandstone reservoir
Energy Procedia, 2011
In most cases, CO2 captured from power plants or large industrial sources contains impurities. As purification of the stream is energy and cost intensive it is necessary to allow a certain level of impurities. The effects of impurities on (short-and long-term) geological storage are, however, uncertain. In this work, geochemical modelling with PHREEQC is performed to describe such effects on a sandstone reservoir (depleted gas field). The impact of two possible CO2 streams, originating from pre-combustion and oxyfuel capture technology is investigated. The streams contain O2, H2, CO, H2S, SO2, and/or NO as potential chemically reactive components. H2S, SO2 and NO are computed to oxidize, thereby forming sulfuric or nitric acid, and decrease the pH of the formation water. A low pH of the brine may be the result of extensive dissolution and dissociation, and therefore accumulation in the brine phase, especially close to the injection well. The impact of impurities on fast reacting minerals (short-term effects) is predicted to be relatively insignificant, due to the low amount of brine generally present in a gas field. On the long-term (equilibrium stage), impurities cause a slightly different mineralogy compared to pure CO2 injection. For the latter case a final increase in porosity of 3.5% is predicted whilst impurities (especially oxygen) could mitigate the porosity increase to zero due to the precipitation of minerals with higher molar volumes, like alunite and nontronite. Overall, the impurities do not seem to have a significant impact on the reservoir, even if accumulation in the brine takes place. The possible limiting effect of diffusion of impurities within the supercritical CO2 towards the brine has not been taken into account, even though the effect could be relevant. It could delay the effect of the impurities due to retarded dissolution. Further research should focus on this issue. Also the spatial effects and effects on different reservoir types, cap rock and well cement need to be investigated.
Energy Procedia, 2014
Rotliegend siliciclastic formations are important reservoirs in central Europe. These sediments consist of pristine red coloured and bleached, high porous and permeable sandstones. To evaluate the relevance of distinct fluids and their fluid-rock alteration reactions on such bleaching processes laboratory static batch experiments under reservoir conditions were conducted. Thereby mineralogical, petrophysical and (hydro-, geo-) chemical rock features were investigated by different analytical methods before and after the experiments. The achieved results suggest that during such fluid-rock interactions a complex interplay between mineral detachment and mineral dissolution processes will control the porosity and permeability of reservoir sandstones.
Heliyon, 2020
Carbon capture and storage (CCS) is expected to play a key role in meeting greenhouse gas emissions reduction targets. In the UK Southern North Sea, the Bunter Sandstone formation (BSF) has been identified as a potential reservoir which can store very large amounts of CO 2 . The formation has fairly good porosity and permeability and is sealed with both effective caprock and base rock, making CO 2 storage feasible at industrial scale. However, when CO 2 is captured, it typically contains impurities, which may shift the boundaries of the CO 2 phase diagram, implying that higher costs will be needed for storage operations. In this study, we modelled the effect of CO 2 and impurities (NO 2 , SO 2 , H 2 S) on the reservoir performance of the BSF. The injection of CO 2 at constant rate and pressure using a single horizontal well injection strategy was simulated for up to 30 years, as well as an additional 30 years of monitoring. The results suggest that impurities in the CO 2 stream affect injectivity differently, but the effects are usually encountered during early stages of injection into the BSF and may not necessarily affect cumulative injection over an extended period. It was also found that porosity of the storage site is the most important factor controlling the limits on injection. The simulations also suggest that CO 2 remains secured within the reservoir for 30 years after injection is completed, indicating that no post-injection leakage is anticipated.
The relative permeability of carbon dioxide (CO2) to brine influences the injectivity and plume migration when CO2 is injected in a reservoir for CO2 storage or enhanced oil recovery (EOR) purposes. It is common practice to determine the relative per- meability of a fluid by means of laboratory measurements. Two principal approaches are used to obtain a relative permeability data: steady state and unsteady state. Although CO2 has been employed in enhanced oil recovery, not much data can be found in the open literature. The few studies available report wide ranges for CO2 relative permeability in typical sedimentary rocks such as Berea sandstone, dolomite, and others. The experimental setups vary for each study, employing steady and unsteady state approaches, different experimental parameters such as temperature, pressure, rock type, etc. and various interpretation methods. Hence, it is inherently difficult to compare the data and determine the origin of differences. It is evident that more experiments are needed to close this knowledge gap on relative permeability. This article concludes that standards for lab measurements need to be defined a. to establish a reliable CO2-brine relative permeability measurement method that can be repeated under the same conditions in any lab and b. to enable comparison of the data to accurately predict the well injection and fluid migration behavior in the reservoir.
Environmental Earth Sciences, 2015
The characterization of the quality and storage capacity of geological underground reservoirs is one of the most important and challenging tasks for the realization of carbon capture and storage (CCS) projects. One approach for such an evaluation is the upscaling of data sets achieved by laboratory CO 2 batch experiments to field scale. (Sub)microscopic, petrophysical, tomographic, and chemical analytical methods were applied to reservoir sandstone samples from the Altmark gas field before and after static autoclave batch experiments at reservoir-specific conditions to study the relevance of injected CO 2 on reservoir quality. These investigations confirmed that the chemical dissolution of pore-filling mineral phases (carbonate, anhydrite), associated with an increased exposure of clay mineral surfaces and the physical detachment and mobilization of such clay fines (illite, chlorite) are most appropriate to modify the quality of storage sites. Thereby the complex interplay of both processes will affect the porosity and permeability in opposite ways-mineral dissolution will enhance the rock porosity (and permeability), but fine migration can deteriorate the permeability. These reactions are realized down to *lm scale and will affect the fluidrock reactivity of the reservoirs, their injectivity and recovery rates during CO 2 storage operations.
Geophysical Research Letters, 2014
Reservoir injectivity and storage capacity are the main constraints for geologic CO 2 sequestration, subject to safety and economic considerations. Brine acidification following CO 2 dissolution leads to fluid-rock interactions that alter porosity and permeability, thereby affecting reservoir storage capacity and injectivity. Thus, we determined how efficiently CO 2 -enriched brines could dissolve calcite in sandstone cores and how this affects the petrophysical properties. During computerized tomography monitored flow-through reactor experiments, calcite dissolved at a rate largely determined by the rate of acid supply, even at high flow velocities which would be typical near an injection well. The porosity increase was accompanied by a significant increase in rock permeability, larger than that predicted using classical porosity-permeability models. This chemically driven petrophysical change might be optimized using injection parameters to maximize injectivity and storage.
Journal of Geophysical Research: Solid Earth
Carbon dioxide (CO 2) injection into deep depleted hydrocarbon reservoirs or saline aquifers is currently considered the best approach to large-scale CO 2 storage. Importantly, the pore structure and permeability of the storage rock are affected by fines release, migration, and reattachment in the initial stage of CO 2 injection, especially in unconsolidated sandstone reservoirs. It is thus necessary to better understand the pore structure changes and the associated permeability evolution during and after CO 2 injection. We thus imaged an unconsolidated sandstone at reservoir conditions before and after CO 2-saturated brine ("live brine") injection in situ via X-ray microcomputed tomography to explore the effects of fines migration and mineral dissolution induced by CO 2 injection. We found that in the examined sample, large pores dominated the total porosity, and porosity slightly increased after live-brine flooding. Moreover, and importantly, the pore structure changed significantly: large pores were further enlarged while small pores shrank or even disappeared. These structural changes in the tested sample were caused by mobilized fines due to the high-fluid interstitial velocity, which eventually reattached to the grains further downstream. Furthermore, the impact of the pore structural changes on permeability were analyzed in detail numerically. These permeability results are consistent with a fines migration mechanism where reattached fines block pore throats and thus decrease permeability drastically. We therefore can conclude that live brine injected into the examined unconsolidated sandstone will slightly improve storage space (porosity slightly increased); however, injectivity may be severely impaired by the permeability reduction.
A Review of the Studies on CO2–Brine–Rock Interaction in Geological Storage Process
Geosciences
CO2–brine–rock interaction impacts the behavior and efficiency of CO2 geological storage; a thorough understanding of these impacts is important. A lot of research in the past has considered the nature and impact of CO2–brine–rock interaction and much has been learned. Given that the solubility and rate of mineralization of CO2 in brine under reservoir conditions is slow, free and mobile, CO2 will be contained in the reservoir for a long time until the phase of CO2 evolves. A review of independent research indicates that the phase of CO2 affects the nature of CO2–brine–rock interaction. It is important to understand how different phases of CO2 that can be present in a reservoir affects CO2–brine–rock interaction. However, the impact of the phase of CO2 in a CO2–brine–rock interaction has not been given proper attention. This paper is a systematic review of relevant research on the impact of the phase of CO2 on the behavior and efficiency of CO2 geological storage, extending to long-...