During CO2 geo-storage, mineral dissolution is considered as the safest trapping technique however it is the longest and the most complicated trapping mechanism involving geo-chemical reactions and physical forces like diffusion and advection. Many factors also influence the mineral trapping capacity of the geological formation e.g., mineralogy, temperature, pH, CO2 fugacity, pressure of CO2, salinity and composition of the brine. The scope of this study is to investigate the mineral trapping of CO2 in Arabian carbonates reservoirs as a function of temperature, brine composition and pH of the subsurface systems. Numerical simulations are performed using the multi-phase simulator GEM-CMG. 2D and 3D models are developed to examine the mechanisms occurring during mineral trapping and how these affect its efficiency. The mineralogy of a carbonate field from an Arabian formation is used. Sensitivity analysis has been performed on the effect of temperature, pH and brine composition on CO2 mineralization tendency and porosity. The results suggest that dissolution and precipitation of minerals occurred during and post CO2 injection while pH had the major influence on mineral trapping. At basic pH conditions, pH=9, the highest amount of CO2 was mineralized while at mid pH, precipitation of carbonates decreased remarkably. Changing the brine composition also highly affected the storage capacity e.g., divalent salt accelerated CO2 mineralization. Moreover, temperature tends to promote the mineral activity during CO2 storage. While a score of publications investigated CO2 storage via structural, residual and dissolution trapping mechanisms, still the mineral trapping potential and its influencing factors have not been investigated much. This paper thus provides new insights into CO2 sequestration by mineral trapping pertinent to Arabian carbonate rocks.
Specialized operations such as Nitro-logging require nitrogen injection in the open hole. The operating parameters of a nitrogen lifting operation in the open hole depend upon several factors that need to be considered which are discussed and optimized in this paper. A decision matrix is created to show the optimum injection rate for nitrogen for different reservoir parameters. In addition, the effect of several completion components is also discussed that can aid in operation. In this project, we examine these factors and deduce the optimum operational conditions for each case based on reservoir and well condition. The controllable operational conditions are gas injection rate and pressure. Different combinations of water cut (WC), reservoir pressure, gas-oil-ratio (GOR), and productivity index (J) are simulated in Wellflo® to predict production in each case. Optimum Economic Factor (OEF), calcultates the efficiency of operation in each case which entails a well's production rate, length of operation, and amount of nitrogen used. The optimum operational conditions are used to populate a decision matrix that incorporates all the examined factors. The analysis of the decision matrix led to the identification of different trends between the operational conditions and reservoir parameters. The main findings were that a higher gas injection rate was required to lift higher WC wells, especially wells with WC greater than 60%. Moreover, wells with GOR less than 1700 scf/stb or wells with J lower than 1 stb/d/psi or wells with reservoir pressure below 2500 psi also required higher gas injection rates. The effects were direr when the well met more than one of these parameters. Additionally, as coiled tubing size increases from 1.25 to 1.5 to 2’’, liquid production decreased from 2250 to 1960 to 1280 bbl/d, respectively. Studying the back pressure from facilities showed that as pressure increased from 0 to 400 to 1000psi, liquid production reduced as well from 700 to 450 to 100 bbl/d, respectively. Considerable economic reduction can be achieved if the operation is optimized as per the results of this project. Overall, the decision matrix eases the operation's planning and execution time while optimizing the quantity of nitrogen gas used.
Wetting characteristics of shale/oil/brine systems at reservoir conditions are important for understanding fluid distribution, flow within shale microstructure, and flow back of fracturing fluid. However, shale wettability demonstrates complexity from core to nanoscale due to microstructure heterogeneity. Shale is believed to exbibit mixed wettability such that the organic matter is hydrophobic or oil-wet and the inorganic mineral is hydrophilic or water-wet. Moreover, the application of nanofluids (e.g., silica) as chemical enhanced oil recovery (CEOR) agents has gained growing interest justified by their promising potential. Thus, to elucidate the complex wetting behavior of shale/oil/brine systems before and after exposure to nanofluids, it is essential to consider the influence of broad mineralogy, TOC (Total Organic Carbon), and aging time of shale surfaces in nanofluids. In this paper, a new physicochemical approach coupled with imaging analysis is proposed to emphasize the interactions of shale/decane/brine systems (before and after aging in nanofluids) for precise shale wettability characterization. Here, the wettability of three US shale oil rocks (Eagle Ford, Wolf Camp, and Mancos) was assessed at ambient and HPHT conditions via advancing and receding contact angle measurements followed by wettability assessment post-aging in different nanofluid concentrations (0.1 wt. % to 5 wt. %). Further, the physicochemical features that influence wettability e.g., surface chemistry, mineral composition, TOC, and kerogen maturity have been investigated. These factors have been assessed via sets of physicochemical measurements such as FTIR (Fourier-Transform Infrared Spectroscopy), XRD (X-Ray Diffraction) analysis, SEM (Scanning Electron Microscopy), and AFM (Atomic Force Microscopy) imaging. Furthermore, the varying thermophysical conditions of pressure and temperature are also investigated. The results revealed significant variations in shale initial wettability with Mancos being weakly water-wet while Eagle Ford and Wolf Camp were moderately oil-wet. Moreover, increasing pressure (from 1 MPa to 20 MPa) shifted the wettability of shale rock surfaces towards relatively more oil-wet witnessed by an increase in advancing and receding contact angles. However, no noticeable trend was observed for contact angle variation with temperature. The original wetting behavior of shales is then related to their functional groups and mineralogy. Additionally, shale surfaces witnessed a shift towards a more water-wet state after aging in silica nanofluids at different concentrations. Therefore, this paper provides a new approach for examining the complex shale wettability behavior that relies on a combination of HPHT conditions, physicochemical analysis, and image analysis. Importantly, the results suggest that nanofluid can alter shale wettability towards a more water-wet state – thus showing potential for application as a flowback additive in fracturing or as a CEOR agent in shales.
Mineral trapping is believed to be the safest and the most secure CO2 sequestration technique where the injected CO2 could be mineralized in the long-term (exceeding 102 - 103 years) geologically within subsurface formations. Nevertheless, the high complexity associated with CO2 mineral trapping capacity predications obscures the in-depth understanding of CO2 mineralization. In this study, a numerical simulation is adopted to demonstrate the impact of carbonate mineralogy in presence of a sealing fault on CO2 mineral trapping capacity. Field-scale CO2 pilot topographic model for three distinct carbonate minerals is simulated to depict the mineral trapping capacity. Thus, realistic petrophysical parameters, reservoir characteristic curves, and other in-situ conditions are upscaled to mimic carbonate formations. Thereafter, the amount of CO2 mineralized is estimated for compositionally distinct reservoirs. Additionally, the effect of injection pressure on CO2 mineralization is assessed upon precipitation/dissolution kinetics calculations. Moreover, the effects of well placement and perforation depth on mineral trapping potential of calcite, dolomite, and siderite dominant reservoirs are assessed. The mineral trapping capacities computed show that increasing injection pressure (base injection pressure to 1.5*base injection pressure) monotonically increased the mineral trapping capacities for calcite and dolomite. However, siderite seems slightly insensitive to the injection pressure increase. This monotonic trend is attributed to enhanced radial displacement and restricted plume migration upward as the injection pressure increases. Moreover, proper CO2 injector placement showed significant enhancement in mineral trapping capacity especially if the injector is near to the fault plane on the leaking side. This study provides in-depth theoretical understanding of the mineralogy effect on CO2 mineralization potential in faulty carbonate sequences. This is driven by the insignificance interest mineral trapping has gained over the years compared to other trapping mechanisms. This is because of the extremely long storage duration needed for mineral trapping to reach its maximum potential. Importantly, the results suggest that CO2 mineralization within carbonate reservoirs immobilize CO2 – thus assisting in stable and long-term permanent storage.
CO2 geo-sequestration has shown potential to mitigate global warming caused by anthropogenic CO2 emissions. In this context, CO2 can be immobilized in subsurface formations due to chemical dissolution/precipitation via mineral trapping. However, long-term mineralization involves interdependent complexity of dissolution and precipitation kinetics. In this study, a numerical approach is developed and implemented to analyze the effect of rock type, reservoir temperature, brine salinity on CO2 mineral trapping in compositionally distinct subsurface carbonate reservoirs. Here, we simulated field-scale models for three different subsurface reservoirs’ compositions (calcite, dolomite, and siderite) to assess the mineral trapping capacity. The base case of a 3D carbonate formation was created. The petrophysical parameters were then upscaled (Sw, Sg, K, and φ) to capture the subsurface conditions. Subsequently, CO2 mineral trapping capacity was computed for different rock compositions mimicking carbonate/brine/CO2 systems. Moreover, the CO2 geo-storage potential was assessed under reservoir temperature, salinity, storage duration, and cumulative injected CO2. The effect of reservoir mineralogy was analyzed via the amount of CO2 mineralized within 100 years of storage duration following 2 years of injection as a base case. The results revealed significant variation in storage capacity as the mineral type changed. In particular, 100% calcite surface showed the highest CO2 storage capacity compared to both dolomite and siderite. The results could be attributed to the distinction of each mineral in terms of its relative cations dissolve-out rate. Moreover, increasing the reservoir temperature resulted in a monotonic increase in mineralization potential with an insignificant increase in case of siderite. Notably, calcite outperformed both siderite and dolomite as a preferable medium for CO2 mineralization as the injection duration increased over both 100 and 200 years of storage. Additionally, the increase in salinity either significantly decreased the amount of CO2 mineralized in case of calcite and siderite or showed no effect at all in case of dolomite. This work provides a new insight for underpinning the effects of carbonate reservoir composition on CO2 mineral trapping capacity which has not been investigated much. Overall, the results showed that CO2 trapping in subsurface carbonates immobilized CO2 for a long-term stable geo-storage.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.