Experimental study of CO2 injectivity impairment in sandstone due to salt precipitation and fines migration

Re-injection of carbon dioxide (CO2) in deep saline formation is a promising approach to allow high CO2 gas fields to be developed in the Southeast Asia region. However, the solubility between CO2 and formation water could cause injectivity problems such as salt precipitation and fines migration. Although both mechanisms have been widely investigated individually, the coupled effect of both mechanisms has not been studied experimentally. This research work aims to quantify CO2 injectivity alteration induced by both mechanisms through core-flooding experiments. The quantification injectivity impairment induced by both mechanisms were achieved by varying parameters such as brine salinity (6000–100,000 ppm) and size of fine particles (0–0.015 µm) while keeping other parameters constant, flow rate (2 cm3/min), fines concentration (0.3 wt%) and salt type (Sodium chloride). The core-flooding experiments were carried out on quartz-rich sister sandstone cores under a two-step sequence. In order to simulate the actual sequestration process while also controlling the amount and sizes of fines, mono-dispersed silicon dioxide in CO2-saturated brine was first injected prior to supercritical CO2 (scCO2) injection. The CO2 injectivity alteration was calculated using the ratio between the permeability change and the initial permeability. Results showed that there is a direct correlation between salinity and severity of injectivity alteration due to salt precipitation. CO2 injectivity impairment increased from 6 to 26.7% when the salinity of brine was raised from 6000 to 100,000 ppm. The findings also suggest that fines migration during CO2 injection would escalate the injectivity impairment. The addition of 0.3 wt% of 0.005 µm fine particles in the CO2-saturated brine augmented the injectivity alteration by 1% to 10%, increasing with salt concentration. Furthermore, at similar fines concentration and brine salinity, larger fines size of 0.015 µm in the pore fluid further induced up to three-fold injectivity alteration compared to the damage induced by salt precipitation. At high brine salinity, injectivity reduction was highest as more precipitated salts reduced the pore spaces, increasing the jamming ratio. Therefore, more particles were blocked and plugged at the slimmer pore throats. The findings are the first experimental work conducted to validate theoretical modelling results reported on the combined effect of salt precipitation and fines mobilisation on CO2 injectivity. These pioneering results could improve understanding of CO2 injectivity impairment in deep saline reservoirs and serve as a foundation to develop a more robust numerical study in field scale.

KOH-Based Modified Solvay Process for Removing Na Ions from High Salinity Reject Brine at High Temperatures

The traditional Solvay process and other modifications that are based on different types of alkaline material and waste promise to be effective in the reduction of reject brine salinity and the capture of CO2. These processes, however, require low temperatures (10–20 °C) to increase the solubility of CO2 and enhance the precipitation of metallic salts, while reject brine is usually discharged from desalination plants at relatively high temperatures (40–55 °C). A modified Solvay process based on potassium hydroxide (KOH) has emerged as a promising technique for simultaneously capturing carbon dioxide (CO2) and reducing ions from reject brine in a combined reaction. In this study, the ability of the KOH-based Solvay process to reduce brine salinity at relatively high temperatures was investigated. The impact of different operating conditions, including pressure, KOH concentration, temperature, and CO2 gas flowrate, on CO2 uptake and ion removal was investigated and optimized. The optimization was performed using the response surface methodology based on a central composite design. A CO2 uptake of 0.50 g CO2/g KOH and maximum removal rates of sodium (Na+), chloride (Cl−), calcium (Ca2+), and magnesium (Mg2+) of 45.6%, 29.8%, 100%, and 91.2%, respectively, were obtained at a gauge pressure, gas flowrate, and KOH concentration of 2 bar, 776 mL/min, and 30 g/L, respectively, and at high temperature of 50 °C. These results confirm the effectiveness of the process in salinity reduction at a relatively high temperature that is near the actual reject brine temperature without prior cooling. The structural and chemical characteristics of the produced solids were investigated, confirming the presence of valuable products such as sodium bicarbonate (NaHCO3), potassium bicarbonate (KHCO3) and potassium chloride (KCl).

RSM for Modelling the CO2 Effect in the Interfacial Tension Between Brine and Waxy Dulang Crude Oil During LSW-WAG EOR

Recent studies on low-salinity waterflooding (LSW) and CO2 water-alternating gas (WAG) use are noteworthy because of their effectiveness in recovered oil content retention in mature fields. s the brine salinity decreases, the solubility of CO2also increases. The CO2in the injected water is expected to reduce the water/oil interfacial tension (IFT), and thus previouslytrapped oil in the rock by capillary forces will flow. However, as of yet, a fewresearches havefocusedon the fluid/fluidinteraction involving waxy crude oil/brinein the LSW-WAGprocess. Twomodels, both of which have been developed from experimental interfacial tension measurements, assist in estimating the CO2's effect on oil/water interfacial tension in the presence and absence of CO2. This objective is accomplished by designing experiments using the modified central composite design (CCD)method in response surface methodology (RSM). Theeffectof pressure, brine salinity, and CO2on oil/water IFT are taken into consideration while modelling.Analysis of variance (ANOVA) was used to determine the optimal values of input variables based on the developed model to obtain an acceptable model. The R-squared values indicate that the developed models arecapable of accurately forecasting the experimental results of oil/water IFT using Dulang crude oil and seven different brine salinities. The findings of this study are expected to shed light on the fluid/fluid interaction behaviour during the LSW-WAG recovery process in a mature field producing waxy crude oil.

Predictive Modelling of CO2 Injectivity Impairment due to Salt Precipitation and Fines Migration During Sequestration

Recent studies indicated that reactive interactions between carbon dioxide (CO2), brine, and rock during CO2 sequestration can cause salt precipitation and fines migration. These mechanisms can severely impair the permeability of sandstone which directly affect the injectivity of supercritical CO2 (scCO2). Previous CO2 injectivity change models are ascribed by porosity change due to salt precipitation without considering the alteration contributed by the migration of particles. Therefore, this paper presents the application of response surface methodology to predict the CO2 injectivity change resulting from the combination of salt precipitation and fines migration. The impacts of independent and combined interactions between CO2, brine, and rock parameters were also evaluated by injecting scCO2 into brine saturated sandstone. The core samples were saturated with NaCl brine with salinity between 6,000 ppm to 100,000 ppm. The 0.1, 0.3, and 0.5 wt.% of different-sized hydrophilic silicon dioxide particles (0.005, 0.015, and 0.060 μm) were added to evaluate the effect of fines migration on CO2 injectivity alteration. The pressure drop profiles were recorded throughout the injection process and the CO2 injectivity alteration was represented by the ratio between the initial and final injectivity. The experimental results showed that brine salinity has a greater individual influence on permeability reduction as compared to the influence of particles (jamming ratio and particle concentration) and scCO2 injection flow rate. Moreover, the presence of both fines migration and salt precipitation during CO2 injection was also found to intensify the permeability reduction by 10%, and reaching up to threefold with increasing brine salinity and particle size. The most significant reductions in permeability were observed at higher brine salinities, as more salts are being precipitated out which, in turn, reduces the available pore spaces and leads to a higher jamming ratio. Thus, more particles were blocked and plugged especially at the slimmer pore throats. Based on comprehensive 45 core flooding experimental data, the newly developed model was able to capture a precise correlation between four input variables (brine salinity, injection flow rate, jamming ratio, and particle concentration) and CO2 injectivity changes. The relationship was also statistically validated with reported data from five case studies.

Morphometric studies of artemia males from different populations of the Altai region

The long-term data from morphometric studies of Artemia males from bisexual and parthenogenetic populations from hyperhaline reservoirs of the Altai region (Bolshoe Yarovoe Lake, Maloe Shklo Lake, and the Tanatar Lakes system) is analyzed in this paper. The description of signs of sexual dimorphism and sexual structure in different populations is given. The influence of brine salinity and hydrogen index on morphometric parameters of males was analyzed. There are differences in the sexual structure of the Artemia population: in the lakes Maloe Shklo and the thanatar system, the populations are bisexual (the share of males is 28.5 — 75.0 %), in the lake Bolshoe yarovoe — parthenogenetic (the share of males on average does not exceed 3 %). At the same time, sexual dimorphism is typical for both types of populations: females are larger than males, males have a larger head (the distance between the eyes is greater by 15.5 %, the diameter of the eye is 26.1 %, the length of the antenna is 22.3 %) and a larger number of bristles (36.1 %). The greatest variability is observed in the parameters of the Furka structure associated with the salinity of water by feedback and the pH — line indicator. Significant differences between the samples of males were revealed. The largest number of significant differences in morphometric indicators was found between samples of males from bisexual populations (lake thanatar and lake Maloe Shklo), the smallest — between males from the parthenogenetic population of lake Bolshoe yarovoe and males from lake Maloe Shklo.

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.