Reservoir Brine Research Articles

Impact-driven mobilization of deep crustal brines on dwarf planet Ceres

Ceres, the only dwarf planet in the inner Solar System, appears to be a relict ocean world. Data collected by NASA’s Dawn spacecraft provided evidence that global aqueous alteration within Ceres resulted in a chemically evolved body that remains volatile-rich1. Recent emplacement of bright deposits sourced from brines attests to Ceres being a persistently geologically active world2,3, but the surprising longevity of this activity at the 92-km Occator crater has yet to be explained. Here, we use new high-resolution Dawn gravity data to study the subsurface architecture of the region surrounding Occator crater, which hosts extensive young bright carbonate deposits (faculae). Gravity data and thermal modelling imply an extensive deep brine reservoir beneath Occator, which we argue could have been mobilized by the heating and deep fracturing associated with the Occator impact, leading to long-lived extrusion of brines and formation of the faculae. Moreover, we find that pre-existing tectonic cracks may provide pathways for deep brines to migrate within the crust, extending the regions affected by impacts and creating compositional heterogeneity. The long-lived hydrological system resulting from the impact might also occur for large impacts in icy moons, with implications for creation of transient habitable niches over time. High-resolution data of Ceres’s bright spots (faculae), obtained by Dawn’s second extended mission, suggest the existence of a deep brine-rich reservoir that emerged to the surface through long-lived cryovolcanic activity as a consequence of the impact that created Occator crater.

Leakoff and Flowback Experiments on Tight Carbonate Core Plugs

Summary In this paper, we investigate the change in oil effective permeability (koeff) caused by fracturing-fluid (FF) leakoff after hydraulic fracturing (HF) of tight carbonate reservoirs. We perform a series of flooding tests on core plugs with a range of porosity and permeability collected from the Midale tight carbonate formation onshore Canada to simulate FF-leakoff/flowback processes. First, we clean and saturate the plugs with reservoir brine and oil, and age the plugs in the oil for 14 days under reservoir conditions (P = 172 bar and T = 60°C). Then, we measure koeff before (baseline) and after the leakoff process to evaluate the effects of FF properties, shut-in duration, and plug properties on regained permeability values. We found that adding appropriate surfactants in FF not only significantly reduces koeff impairment caused by leakoff, but also improves koeff compared with the original baseline for a low-permeability carbonate plug. For a plug with relatively high permeability (kair > 0.13 md), freshwater leakoff reduced koeff by 55% (from 1.57 to 0.7 md) while FF (with surfactants) reduced koeff by only 10%. The observed improvement in regained koeff is primarily because of the reduction of interfacial tension (IFT) by the surfactants (from 26.07 to 5.79 mN/m). The contact-angle (CA) measurements before and after the flowback process do not show any significant wettability alteration. The results show that for plugs with kair > 0.13 md, FF leakoff reduces koeff by 5 to 10%, and this range only increases slightly by increasing the shut-in time from 3 to 14 days. However, for the plug with kair < 0.09 md, the regained permeability is even higher than the original koeff before the leakoff process. We observed 28.52 and 64.61% increase in koeff after 3- and 14-day shut-in periods, respectively. This observation is explained by an effective reduction of IFT between the oil and brine in the pore network of the tight plug, which significantly reduces irreducible water saturation (Swirr) and consequently increases koeff. Under such conditions, extending the shut-in time enhances the mixing between invaded FF and oil/brine initially in the plug, leading to more effective reductions in IFT and consequently Swirr. Finally, the results show that the regained permeability strongly depends on the permeability, pore structure, and Swirr of the plugs.

Simulation Study on Reservoir Souring Induced by Injection of Reservoir Brine Containing Sulfate-Reducing Bacteria

This paper examined the reservoir souring induced by the sulfate-reducing bacteria (SRB) inhabiting the reservoir brine of an oilfield in Japan. Although the concentration of sulfate of the reservoir brine was lower than that of seawater, which often was injected into oil reservoir and induced the reservoir souring, the SRB inhabiting the reservoir brine generated hydrogen sulfide (H2S) by using sulfate and an electron donor in the reservoir brine. This paper therefore developed a numerical simulator predicting the reservoir souring in the reservoir into which the reservoir brine was injected. The results of the simulation suggested that severe reservoir souring was not induced by the brine injection; however, the SRB grew and generated H2S around the injection well where temperature was decreased by injected brine whose temperature was lower than that of formation water. In particular, H2S was actively generated in the mixing zone between the injection water and formation water, which contained a high level of the electron donor. Furthermore, the results of numerical simulation suggested that the reservoir souring could be prevented more surely by sterilizing the SRB in the injection brine, heating up the injection brine to 50 °C, or reducing sulfate in the injection brine.

Oil recovery from fractured porous media with/without initial water saturation by using 3-pentanone and its aqueous solution

This paper presents an application of 3-pentanone, a symmetric dialkyl ketone, to enhance the water imbibition in coreflooding of fractured carbonate cores. 3-Pentanone was tested in two ways: 1.1- wt% 3-pentanone solution in reservoir brine (3pRB) and pure 3-pentanone (3p) as a miscible solvent. It was presented previously that 3p is a mutual solvent for oil and water, and can rapidly change the rock wettability to strongly water-wet with its electron-rich oxygen atom through the oil and water phases. The main objective of this research is to investigate how the initial water saturation (Swi) in the matrix affects the imbibition of 3pRB or 3p from the fracture and the resulting recovery of oil from the matrix.The experimental results were analyzed in terms of material balance (mass and volume) with simplifying assumptions. This analysis enabled to estimate how much of the injected components were imbibed into the surrounding matrices from the fracture and the relative contribution of the injected components to displacing oil in the matrix. Results for the 3pRB and 3p injections indicate collectively that 3-pentanone was more effective in enhancing oil recovery when an aqueous phase was initially present in the matrix.

The Investigation of Silica Nanoparticles-CO2 Foam Stability for Enhancing Oil Recovery Purpose

Carbon dioxide (CO2) gas injection is one of the most successful Enhanced Oil Recovery (EOR) methods. But the main problem that occurs in immiscible CO2 injection is the poor volumetric sweep efficiency which causes large quantities of the oil to be retained in pore spaces of reservoir. Although this problem can be improved through the injection of surfactant with CO2 gas where the surfactant will stabilize CO2 foam, this method still has some weaknesses due to foam size issue, surfactants compatibility problems with rocks and reservoir fluids and are less effective at high brine salinity and reservoir temperature such as typical oil reservoirs in Indonesia. This research aims to examine the stability of the foams/emulsions, compatibility and phase behavior of suspensions generated by hydrophobic silica nanoparticles on various salinity of formation water as well as to determine its effect on the mobility ratio parameter, which correlate indirectly with macroscopic sweep efficiency and oil recovery factor. This research utilizes density, static foam, and viscosity test which was carried out on various concentrations of silica nanoparticles, brine salinity and phase volume ratio to obtain a stable foam/emulsion design. The results showed that silica nanoparticles can increase the viscosity of displacing fluid by generating emulsions or foams so that it can reduce the mobility ratio toward favorable mobility, while the level of stability of the emulsion or foam of the silica nanoparticles suspension is strongly influenced by concentration, salinity and phase volume ratio. The high resistance factor of the emulsions/foams generated by silica nanoparticles will promote better potential of these particles in producing more oil.

Modeling CO2 plume migration using an invasion‐percolation approach that includes dissolution

AbstractGeological carbon dioxide (CO2) sequestration has been proposed as a viable technique to decrease effective emissions of CO2 into the atmosphere. However, the security of this sequestration is tied to our understanding of the long‐term migration of CO2 in subsurface. The dissolution of CO2 in the reservoir brine is one of the main long‐term trapping mechanisms. However, the assumptions used in large‐scale reservoir simulations usually lead to an overestimation of the dissolution volume. We propose a modified approach based on the macroscopic invasion‐percolation (MIP) theory that allows the dissolution of CO2 into brine. We used a high‐resolution geological model to compare the Darcy‐, modified MIP‐, and classic MIP‐based simulation results. We observed a significant shrinkage in the nonaqueous plume volume when dissolution is considered during the MIP simulation. In the case of Darcy‐based simulation, the plume was completely trapped inside the reservoir with limited migration even after a thousand‐year simulation. On the other hand, the majority of the plume migrated out of the simulated reservoir in the case of MIP. Our approach provides more realistic estimation of the dissolution volume and nonaqueous plume extent while leveraging the computational efficiency enjoyed by MIP. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

The use of environmental tracers to characterize a leaky CO2 CCS natural analogue site, Soda Springs, Idaho, USA

AbstractLarge‐scale global adoption of carbon capture and storage (CCS) as a means of minimizing atmospheric CO2 emissions requires an unprecedented effort to store gigatons of anthropogenic emissions in the earth's subsurface. Critical to the adoption and ultimate success of CCS is the protection of valuable water resources that may be impacted by leaking CO2 from CCS operations. Therefore, appropriate technical tools and societal controls will need to be developed and evaluated to maximize the atmospheric benefits of CCS while limiting potential deleterious effects of its implementation. Here, we utilize a naturally leaking CO2 system located at Soda Springs, Idaho, USA, as an analogue for industrial‐scale CCS deployment. This site is particularly relevant and useful for studying the consequences of CCS because it allows the examination of geologic systems at temporal and spatial scales not accessible by laboratory and field experiments.The Soda Springs system is an ideal CCS natural analogue site with the source of CO2 occurring at depths and temperatures expected for large‐scale CCS systems. Soda Springs also provides long‐term examples of at least three potential failure modes for CCS systems, including direct migration of CO2 charged brine to the surface via faulting or wells, upward movement of CO2 from the injection‐horizon into over lying shallow aquifers, and the displacement of reservoir brine into shallower aquifers. These failure mechanisms were differentiated and characterized utilizing variations in water chemistry including rare earth elements providing a framework for delineating the movement of CO2‐influenced fluids migrating from deep CCS reservoirs into overlying aquifers. © 2020 Society of Chemical Industry and John Wiley & Sons, Ltd.

Low salinity effect on the recovery of oil trapped by nanopores: A molecular dynamics study

Low salinity waterflooding (LSW) is an effective method for enhancing the oil recovery from many reservoirs, and its success has been traced to a host of low salinity effects. In this work, we perform molecular dynamics simulations to study the feasibility of recovering oil trapped by nanopores by lowering the reservoir salinity. The oil is initially trapped by a slit nanopore, with a portion of the oil protruding from the pore entrance. After the reservoir salinity is lowered, the thin brine films that separate the oil and pore walls become thicker to drive some of the trapped oil out of the pore. We quantify the free energy profile of this process and clarify the underlying molecular mechanisms. Interestingly, the brine film growth is dominated by the water transport from the brine reservoir into the pore rather than by the depletion of ions from the brine film. These results provide molecular evidence that low salinity brines benefit the recovery of the oil trapped by nanopores. They highlight that when ion depletion from thin brine films is suppressed, the osmosis of water can play a fundamental role in the expansion of the brine films; thus, the enhanced oil recovery. The slow osmosis of water through thin brine films and thus the slow displacement of oil from the pore may help explain the anomalously slow oil recovery reported in micro-modeling experiments of LSW.

Ketone solvent as a wettability modifier for improved oil recovery from oil-wet porous media

The main objective of this research is to investigate a novel class of oxygenated solvents that can enhance the oil recovery from oil-wet rocks by multiple mechanisms, such as wettability alteration, oil-viscosity reduction, and oil swelling, in the presence of brine (connate water and/or fracturing water). The compound studied for the first time in this research is 3-pentanone (3p), a symmetric short ketone that can partition into both oil and brine at reservoir conditions. It can act as a solvent by itself, but this paper is focused on the potential mechanisms of oil recovery when an aqueous solution of 1.1 wt% 3p in reservoir brine (3pRB) is in contact with oil and oil-wet rock.Results show that the average contact angle of oil droplets on oil-aged calcite surfaces was rapidly reduced to 26° with 3pRB, in contrast to 123° with RB, without affecting the oil/brine interfacial tension. Spontaneous imbibition results show that the oil recovery factor reached 50.0% with 3pRB and 10.0% with RB at Day 3. The final recovery factor was 51.0% with 3pRB and 12.0% with RB. The subsequent forced imbibition determined the Amott index to water of 0.76 with 3pRB and 0.23 with RB, indicating a clear, positive impact of 3pRB on oil recovery by water imbibition in the cores tested. The main mechanism of oil recovery by 3pRB in this research is the wettability change as demonstrated by the contact-angle experiment.

Impact of Divalent Ions on Heavy Oil Recovery by in situ Emulsification

AbstractMany reservoir formation brines are characterized by high salinity and contain high concentrations of divalent ions such as calcium, magnesium, and potassium. These challenging conditions can render the surfactants ineffective during chemical flooding for enhanced heavy oil recovery. Various brine types can have an impact on the stability of emulsions generated with chemicals as chemicals have various resistant levels toward hard divalent ions and salinities. To investigate the impact of brine hardness on heavy oil‐in‐water emulsion stability, glass tube experiments, microscopic visualization and sandpack flooding experiments, and Hele‐Shaw visualization experiments were conducted in this study under low‐salinity/hard‐brine, high‐salinity/hard‐brine conditions using commercial chemicals, which are designed for specific reservoir brine conditions. Recovery results demonstrated that complex colloidal solution introduced in the previous study with silica and Dodecyltrimethylammonium bromide (DTAB) along with screened chemicals from glass tube tests in this study can enhance heavy oil recovery significantly with an addition of low concentration of xanthan gum (Lee and Babadagli 2018). The results confirmed the robustness of the complex colloidal solution formula to enhance oil recovery with low concentration of polymer under any reservoir brine conditions. The study also demonstrates the potential of polymer as an emulsion stabilization additive for enhanced heavy oil recovery by in situ emulsion generation. Polymer effects seemed to be particularly dominant under the low‐salinity conditions than high‐salinity conditions.

Geochemistry in geologic CO2 utilization and storage: A brief review

In this brief review, a comprehensive collection of previous studies about geochemistry in geologic CO2 utilization and storage is presented and discussed to demonstrate the importance of CO2-rock and CO2-wellbore cement interactions in geologic CO2 utilization and storage scenarios. For CO2-rock interaction, CO2 injection reduces the pH of brine in CO2 storage reservoir, which triggers dissolution of silicate and oxide minerals in the reservoir. Dissolution of silicate and oxide minerals causes concentration increase of cations and anions, which induces secondary precipitation of silica, silicates and carbonates. For CO2-cement interaction, the interaction between CO2 and wellbore cement results in formation of a unique “sandwich” structure in cement (i.e., one carbonate precipitation zone in the middle and two dissolution zones on two sides). For both CO2-rock and CO2-cement interactions, pH plays a key role in the extent of mineral dissolution and precipitation, and the extent is dependent on pH buffering capacity of the CO2 storage reservoir. The potential of CO2-induced contaminant mobilization in deep CO2 storage reservoir and shallow aquifer is also discussed, and the chance for CO2 injection and CO2 leakage to cause severe shallow aquifer contamination is low. Cited as : Zhang, L., Wang, Y., Miao, X., Gan, M., Li, X. Geochemistry in geologic CO2 utilization and storage: A brief review. Advances in Geo-Energy Research, 2019, 3(3): 304-313, doi: 10.26804/ager.2019.03.08

Synergistic application of aluminium oxide nanoparticles and oilfield polyacrylamide for enhanced oil recovery

Due to the inherent limitation of oilfield polyacrylamide in reservoir temperature and salinity, nanoparticles (NPs) have been extensively studied for their application in enhanced oil recovery (EOR) because of their unique properties and availability in large quantities. Recent trend in nanotechnology involves incorporating NPs as additive with polymer to form novel materials termed polymeric nanofluids (PNF's) for EOR. However, previous studies have investigated and focussed more on the suitability of silica (SiO2) polymeric nanofluids. In this work, the potential application of metal oxide polymeric nanofluid for EOR was explored and evaluated. Aqueous HPAM-based Al2O3 PNF's were formulated and characterised using Transmission Electron Microscopy (TEM) and Fourier-transform infrared (FTIR) spectroscopy. The performance of aluminium oxide (Al2O3) NP on the rheological properties of HPAM in the presence of different electrolyte concentrations representative of field brine and typical reservoir temperatures were investigated. Wettability alteration study of Al2O3 PNF was carried out using DataPhysics optical contact angle (OCA) instrument. Results obtained for Al2O3 PNF were compared to the widely reported SiO2 PNF and base polymer without nanomaterial. Experimental results show that the rheological properties improved while degradation of HPAM macromolecule was inhibited due to the addition of NPs. At 2,000 ppm HPAM solution (25 mol. % degree of hydrolysis), 0.1 wt% NP concentration was found to be the optimal choice for Al2O3 NP which gives rise to the highest viscosity on the rheological characterization. Al2O3 PNF exhibited better steady shear viscosity performance under the different electrolyte concentrations and temperatures studied. Al2O3 PNF altered the wettability of the porous media from oil-wet to water-wetting condition. Finally, oil displacement test in sandstone cores at typical reservoir temperature and salinity showed that Al2O3 PNF had 11.3% incremental oil recovery over conventional HPAM. This study is beneficial for extending the frontier of knowledge in nanotechnology application for EOR.

Experimental Study on Spontaneous Imbibition of CO2-Rich Brine in Tight Oil Reservoirs

This paper focuses on the CO2-EOR in fractured tight oil reservoirs after water-flooding treatment. In previous works, few studies were presented about the spontaneous imbibition experiments of CO2-rich brine at formation pressure. We investigated the influence of CO2 injection on spontaneous imbibition, which is an essential mechanism to improve oil recovery in tight reservoir. In this paper, a laboratory equipment was set up to conduct spontaneous imbibition experiments at formation temperature of 65 °C and pressures of 10–22 MPa on different low-permeability core samples from Nugget, Kentucky, Colton, and Crab-Orchard in the United States. Moreover, we proposed a saturation-based dimensionless time model to scale the spontaneous imbibition and a modified Ma model to fit the oil recovery curves of spontaneous imbibition of CO2-rich brine with double peaks of imbibition rate. The results of quantitative imbibition experiments confirm that both the oil production per unit area and the oil recovery have a ...

Calibration of NMR porosity to estimate permeability in carbonate reservoirs

Understanding the performance of carbon dioxide (CO2) stored in geologic reservoirs requires some knowledge of the subsurface heterogeneity, where the most reliable data is extracted from wellbore measurements. This advantage is especially true for carbonate reservoirs were reactions between supercritical CO2, the reservoir brine, and carbonate minerals create new storage capacity and enhanced permeability. Techniques like NMR well logging hold promise for estimating subsurface permeability, because the total porosity and pore size can be calculated from response of 1H NMR signal. Resulting depth profiles of porosity and permeability from downhole logs are useful input for reservoir simulations and can be used to design injection protocols and estimate storage capacity.We conducted a detailed characterization study to quantify the NMR response to matrix pore space, the connectivity to larger vugs and fractures, and the resulting permeability of core samples from distinct carbonate formations. The cores used in study span 5 orders in permeability, 4 orders in mean T2, and 2%–42% in porosity. The goal of the study was to use independent measures of pore volumes, surface relaxivity, fluid-accessible surface areas, and permeability to develop carbonate permeability models.It was not possible to develop a single model that reproduced permeability for different carbonate formations, because phenomena specific to the reservoirs could not be extracted even with the state-of-the-art characterization techniques used in this study. Estimates of permeability require calibration. Best estimates for a given formation were achieved by using a simple form of the Kozeny equation (Eq. 6):

Adaptive Pressure Management and Plume Control in Geological Co2 Storage: Designing a Brine Extraction Field Experiment

Industrial scale injection of CO2 into the subsurface can result in significant fluid pressure increases, which can lead to potential environmental impacts such as caprock fracturing, fault activation and leakage into underground fresh water aquifers. Pressure management through brine extraction is an approach for managing formation pressure, effective stress, and plume movement in response to CO2 injection. However, the handling and management of the extracted brine has a cost that is added to carbon capture and sequestration (CCS) operations; therefore minimizing the extracted volume of brine can be of great importance. At the same time, economics of pressure management via brine extraction can be improved by treating the extracted high-salinity water and making it available for beneficial uses, for example as cooling water for power plants. In this paper, we introduce and demonstrate application of an adaptive reservoir management approach that optimizes extraction rates of reservoir brines for pressure control in an integrated optimization framework. Our approach will be tested during a brine extraction field experiment located in the southern United States, which is currently in the design and planning stages. The objective of the experiment is to evaluate the technical feasibility of managing subsurface pressures associated with large-scale CO2 injection volumes and to assess the cost and effectiveness of desalination technologies for saline waters containing high total dissolved solids (TDS). Our integrated adaptive management approach involves monitoring, model calibration, and optimization of brine extraction for pressure control. Based on measurements obtained during the injection phase and utilizing improved predictive models from repeated calibration, initial optimization calculations will be revised in regular intervals and the operating decisions for controlling and managing subsurface pressurization will be updated. In this paper, in preparation of the actual field demonstration, we investigate use of borehole measurements (i.e., pressure changes) and electromagnetic (EM) geophysical methods (i.e. salinity changes) in the adaptive management of the injection and brine extraction project. We also present a numerical exercise to investigate how the optimization performance is affected by the quality of initial site characterization data and by the frequency of dynamic model updates with newly acquired data during the injection. Our numerical study shows that more accurate initial reservoir characterization data reduce the risk of pressure buildup above a given maximum pressure because the optimization algorithm arrives at better estimates of initial extraction rates, which in turn results in better control of pressure during the overall injection times. Results also show that low frequencies of model calibration and optimization with the new data, especially at early injection periods, may lead to optimization problems, either because pressure buildup constraints are violated or excessively high extraction rates are proposed. These optimization problems can be eliminated if more frequent data collection and model calibration are conducted, especially at early injection times. Approaches such as adaptive pressure management may constitute an effective tool to manage pressure buildup under uncertain reservoir conditions by minimizing the brine extraction volumes while controlling pressure buildups. This will be demonstrated in the actual field study, with injection planned to start in early 2019.

Hydrochemistry as a tool for interpreting brine origin and chemical equilibrium in oilfields: Zubair reservoir southern Iraq case study

The oil reservoir brines are very common geological fluids coexisting with hydrocarbons. The chemistry of brines is a powerful tool for determining the brine evolution and its origin, constraining fluid flow at the basin and predicting reservoir scales. This study targeted the Zubair brines in seven oilfields and investigated the geochemical evolution of brine compositions. The composition of the Zubair brine is characterized by the high average of TDS (219,408 mg/l). The contribution of cations as epm% are Na (73.7), Ca (17.32), Mg (7.45), and K (1.27), while anions contribute as Cl (99.6), SO4 (0.23), HCO3 (0.08), and CO3 (0.005). The Zubair brines are of Na–Ca–chloride type, whereas sodium content is 6.3 times greater than seawater; Ca and Mg contents are thirty-four and three times greater, respectively, while Cl is seven times greater. The SO4 ion is depleted to 0.16, due to a biodegradation. The salinity of the Zubair brine is six times more than that of seawater. The Zubair brines are characterized by an acidic pH (5.24–5.68) with a specific gravity of 1.1436, hydrocarbon saturation in pore spaces of 39%, and water saturation of 61%. The mineral saturation model indicates that Zubair brines are unsaturated. The predicted hypothetical salts are NaCl (76%), CaCl2 (15%), and MgCl2 (7.5%). The salts Ca(HCO3)2, CaSO4, and KCl together form only 1.6%. The Zubair brines are characterized by Cl/Br (305) in average, greater than that of seawater (289) confirming the fluids (brines and hydrocarbons) migrated upwards from Sargelu Formation to Zubair reservoir through fractures and cracks in Gotnia Formation.

A Novel Approach to Stabilize Foam Using Fluorinated Surfactants

Selection of surfactants for enhanced oil recovery and other upstream applications is a challenging task. For enhanced oil recovery applications, a surfactant should be thermally stable, compatible with reservoir brine, and have lower adsorption on reservoir rock, have high foamability and foam stability, and should be economically viable. Foam improves the oil recovery by increasing the viscosity of the displacing fluid and by reducing the capillary forces due to a reduction in interfacial tension. In this work, foamability and foam stability of two different surfactants were evaluated using a dynamic foam analyzer. These surfactants were fluorinated zwitterionic, and hydrocarbon zwitterionic surfactants. The effect of various parameters such as surfactant type and structure, temperature, salinity, and type of injected gas was investigated on foamability and foam stability. The foamability was assessed using the volume of foam produced by injecting a constant volume of gas and foam stability was determined by half-life time. The maximum foam generation was obtained using hydrocarbon zwitterionic surfactant. However, the foam generated using fluorinated zwitterionic surfactant was more stable. A mixture of zwitterionic fluorinated and hydrocarbon fluorinated surfactant showed better foam generation and foam stability. The foam generated using CO2 has less stability compared to the foam generated using air injection. Presence of salts increases the foam stability and foam generation. At high temperature, the foamability of the surfactants increased. However, the foam stability was reduced at high temperature for all type of surfactants. This study helps in optimizing the surfactant formulations consisting of a fluorinated and hydrocarbon zwitterionic surfactant for foam injections.

Conditions for the Long‐Term Preservation of a Deep Brine Reservoir in Ceres

AbstractWe propose a new internal evolution model for the dwarf planet Ceres matching the constraints on Ceres' present internal state from the Dawn mission observations. We assume an interior differentiated into a volatile‐dominated crust and rocky mantle, and with remnant brines in the mantle, all consistent with inferences from the Dawn geophysical observations. Simulations indicate Ceres should preserve a warm crust until present if the crust is rich in clathrate hydrates. The temperature computed at the base of the crust exceeds 220 K for a broad range of conditions, allowing for the preservation of a small amount of brines at the base of the crust. However, a temperature ≥250 K, for which at least 1 wt.% sodium carbonate gets in solution requires a crustal abundance of clathrate hydrates greater than 55 vol.%, a situation possible for a narrow set of evolutionary scenarios.

Brine chemistry effects in calcite dissolution kinetics at reservoir conditions

Understanding the chemical interactions between CO2-saturated brine systems and reservoir rocks is essential for predicting the fate of CO2 following injection into a geological reservoir. In this work, the dissolution rates of calcite (CaCO3) in CO2-saturated brines were measured at temperatures between 325 K and 373 K and at pressures up to 10 MPa. The experiments were performed in batch reactors implementing the rotating disk technique in order to eliminate the influence of fluid-surface mass transport resistance and obtain surface reaction rates. Three aqueous brine systems were investigated in this study: NaCl at a molality m = 2.5 mol·kg−1, NaHCO3 with m ranging from (0.005 to 1) mol·kg−1 and a multicomponent Na-Mg-K-Cl-SO4-HCO3 brine system with an ionic strength of 1.8 mol·kg−1. Measured dissolution rates were compared with predictions from previously published models. Activity calculations were performed according to the Pitzer model as implemented in the PHREEQC geochemical simulator. Calcite dissolution rates in NaCl and the multicomponent brine system showed minor increases when compared to the (CO2 + H2O) system at identical conditions, despite the lower concentration of dissolved CO2. These trends are consistent with the expected minor decreases in solution pH. In NaHCO3 systems, consistent with increase in solution pH, significant decreases in dissolution rates were observed. In addition, these systems significantly deviated from model predictions at higher salt molalities. Vertical scanning interferometry (VSI) was used to examine the mineral surfaces before and after dissolution experiments to provide qualitative information on saturation states and dissolution mechanism.

Modelling Medium-Depth CO2 Injection at the Svelvik CO2 Field Laboratory in Norway

The CO2 field laboratory at the Svelvik ridge near Oslo, Norway, is presently being upgraded as part of the European research infrastructure initiative (the ECCSEL laboratories). The test site was established in 2010 by the SINTEF-coordinated CO2FieldLab project with the overall objective to study the performance of monitoring systems to detect and quantify CO2 migration and leakage. At the site there is a possibility of injecting CO2 in a sand-rich sedimentary interval at 60-m depth, under a clay-rich interval. The feasibility of using geophysical monitoring methods to detect and quantify such an injection was studied earlier for injection of nitrogen. Nitrogen, with a low solubility in brine, was used to get a clear saturation response. In this paper we revisit the modelling work and extend the scenarios by also modelling injection of CO2. The large difference between solubility of N2 and CO2 in reservoir brine gives markedly different behaviour of the injected gases. Results from these modelling studies will be useful in the mapping of options for future projects at the field laboratory.