Environmental influences on the vapourside corrosion of copper-nickel alloys

Corrosion of copper-nickel alloys in pure water

The principal mechanisms for the geologic sequestration of carbon dioxide in deep saline formations include geological structural trapping, hydrological entrapment of nonwetting fluids, aqueous phase dissolution and ionization, and geochemical sorption and mineralization. In sedimentary saline formations the dominant mechanisms are structural and dissolution trapping, with moderate to weak contributions from hydrological and geochemical trapping; where, hydrological trapping occurs during the imbibition of aqueous solution into pore spaces occupied by gaseous carbon dioxide, and geochemical trapping is controlled by generally slow reaction kinetics. In addition to being globally abundant and vast, deep basaltic lava formations offer mineralization kinetics that make geochemical trapping a dominate mechanism for trapping carbon dioxide in these formations. For several decades the United States Department of Energy has been investigating Columbia River basalt in the Pacific Northwest as part of its environmental programs and options for natural gas storage. Recently this nonpotable and extensively characterized basalt formation is being reconsidered as a potential reservoir for geologic sequestration of carbon dioxide. The reservoir has an estimated storage capacity of 100 giga tonnes of carbon dioxide and comprises layered basalt flows with sublayering that generally alternates between low permeability massive and high permeability breccia. Chemical analysis of themore » formation shows 10 wt% Fe, primarily in the +2 valence. The mineralization reaction that makes basalt formations attractive for carbon dioxide sequestration is that of calcium, magnesium, and iron silicates reacting with dissolved carbon dioxide, producing carbonate minerals and amorphous quartz. Preliminary estimates of the kinetics of the silicate-to-carbonate reactions have been determined experimentally and this research is continuing to determine effects of temperature, pressure, rock composition and mineral assemblages on the reaction rates. This study numerically investigates the injection, migration and sequestration of supercritical carbon dioxide in deep Columbia River basalt formations using the multifluid subsurface flow and reactive transport simulator STOMP-CO2 with its ECKEChem module. Simulations are executed on high resolution multiple stochastic realizations of the layered basalt systems and demonstrate the migration behavior through layered basalt formations and the mineralization of dissolved carbon dioxide. Reported results include images of the migration behavior, distribution of carbonate formation, quantities of injected and sequestered carbon dioxide, and percentages of the carbon dioxide sequestered by different mechanisms over time.« less

A laboratory approach on the improvement of oil recovery and carbon dioxide storage capacity improvement by cyclic carbon dioxide injection

Analytical study of CO2–CH4 exchange in hydrate at high rates of carbon dioxide injection into a reservoir saturated with methane hydrate and gaseous methane

Numerical simulation and optimization of CO2-enhanced water recovery by employing a genetic algorithm

Economic Feasibility of Carbon Sequestration with Enhanced Gas Recovery (CSEGR)

Container system to actively keep modified atmosphere of high carbon dioxide concentration by automated control was designed and tested to store kimchi, a Korean fermented vegetable at high sensory preference for long time period. The system was constructed with a 10 L stainless steel container with plastic cover installed with quick-connecting and check valves. Hypobaric vacuumizing from the vacuum pump and carbon dioxide injection from the carbon dioxide cylinder were combined or used in a programmed automatic mode timely in accordance with the progress of kimchi fermentation. Two storage tests were conducted: one at chilled temperature of 10 °C and the other of storage at 10 °C followed by a higher temperature of 25 °C. The container was filled initially with 8 kg of kimchi (salt content of 2.6-2.7%), closed with a cover and flushed with carbon dioxide. The process of repetitive vacuumizing/carbon dioxide injection reached the internal carbon dioxide partial pressure higher than 0.9 atm. During the storage, carbon dioxide gas was injected into the container for 15 seconds every 12 hours or every 24 hours depending on the kimchi ripening progress through the carbon dioxide supply line to supplement the carbon dioxide that is dissolved into the kimchi or lost. A container simply closed without vacuumizing and carbon dioxide injection was submitted to the same storage and opening/closing conditions for the purpose of control. During the storage, the containers were opened and closed intermittently often with taking out some kimchi to simulate consumer behavior, and then the same procedure of hypobaric treatment and carbon dioxide injection was followed for the CO2-controlled one. Container atmosphere and product quality were measured through the storage. Compared to the control container, the CO2-controlled container system improved the sensory flavor of kimchi in the whole storage period and inhibited the growth of spoilage yeasts with the extended storage at both the chilled and abuse temperatures.

Due to the unique corrosion potential and safety hazards of carbon dioxide (CO), tubing leakage of CO in a CO injection well may occur and lead to undesired consequences to environment, human being and facility. As a result, quick detection of any carbon dioxide leakage and accurate identification of leakage location are extremely beneficial to obtain critical information to fix the leakage in a prompt manner, prevent incidents / injury / casualty, and achieve high standards of operational safety. Annular pressure monitoring has been identified as an effective and reliable approach for detecting tubing and casing leakage of fluids (including hazardous gas like CO) in a well. Accurate prediction of annular pressure change associated with the leakage will certainly help the operation. In an effort to assess annular pressure characteristics and thus improve understanding of tubing leakage, a multiphase dynamic modeling approach has been applied to simulate the carbon dioxide, completion brine and formation water’s flow and associated heat transfer processes along wellbore, tubing and annulus in carbon dioxide injection wells designed for carbon capture and sequestration (CCS) [1] projects. Two operational scenarios – one for routine CO injection and another for well shut-in – have been considered in the investigation. Key parameters that may have significant impacts on the process have been investigated. On the basis of the investigation, a novel approach has been proposed in the paper for quickly detecting the leakage of carbon dioxide in a CO injection well. Two simple equations have been developed to pinpoint the leakage location by means of real-time measurement and monitoring of the change in annular pressure. Recommendations based on a series of dynamic simulation results have been provided and can be readily incorporated into detailed operating procedures to enhance carbon dioxide injection wells’ operational safety.

Currently, there is a great deal of interest in carbon dioxide for the recovery of both heavy and light oils. This paper deals with an investigation of the efficiency of gaseous carbon dioxide as a recovery agent for moderately viscous oils. The paper gives numerical model results, and compares and contrasts the findings with laboratory and field test observations, pointing out the range of conditions over which carbon dioxide is likely to be effective. The carbon dioxide injection simulator used simulates three- phase flow, and was checked out for numerical dispersion grid effects, material balance, etc. It was then employed for a variety of carbon dioxide injection simulations. The base cases were in qualitative agreement with the reported experimental data. It was found that over the viscosity range of J 10 1000 mPa.s, carbon dioxide was superior to natural depletion, inert gas injection or water flooding, jar oil viscosities above 70 mPa. s. The gain over water flooding was as much as 9 per cell· tiles in oil recovery, being greater for the more viscous crudes. Oil saturation was an important variable, as oil recovery decreased rapidly with a decrease in saturation. Another significant factor affecting ultimate oil recovery was the critical gas saturation. Viscous oils showed a 27% increase in recovery as the critical gas saturation varied from 0 to 10%. The blow down recovery on curtailment 0/ carbon dioxide injection was about 1 percentile; field values are as high as 4 percentiles. Reasons for this discrepancy are outlined. The amount of carbon dioxide left in the reservoir was used as a measure of the efficiency of the process; it was high for low oil saturations, especially for the more viscous oils. An economic analysis of the carbon dioxide injection process showed that the economics are tenuous; a variety of factors in addition to the oil price would determine the economic viability of the process. Introduction Although there is little debate that a significant amount of oil remains held in the ground by current technical and economic constraints, opinion is widespread as to the proper recovery technique or techniques to unlock these reserves. (Infill drilling and a handful of alternative recovery methods, such as thermal, miscible and improved mobility floods, compete for the over 52 billion cubic metres of United States and Canadian oil (<980 Kg/m3) that remains in place. Carbon dioxide injection, as one of these processes, has long been thought of as a miscible process best applied in light oils with densities less than 930 Kg/m3. However, immiscible carbon dioxide flooding as part of the suite of enhanced oil recovery methods being tested may be promising in the case of heavy, moderately viscous oils where carbon dioxide injection improves recovery by lowering oil viscosity and promoting swelling. Deposits of heavy oil total over one-half trillion metres3 in the U.S., Venezuela and Canada. In the U.S. alone, there are over 2,000 heavy oil reservoirs occurring in 1500 fields in 26 states.

At the current stage of development of the oil and gas industry in the world, the processing and utilization of carbon dioxide at the fi eld itself is of interest, which makes it possible to save energy resources during its capture and injection into the well space, which is important for Russia due to the remoteness of the main part of the fi elds. Due to the release of associated gases, in particular, hydrogen, there is a possibility to generate additional energy for own needs at the fi eld and, in addition, to minimize greenhouse gas emissions. It is noted that supercritical fl uid carbon dioxide has a list of advantages, including the absence of toxicity, fi re, explosion hazard, as well as low cost and availability and serves as an environmentally safe solvent. To the technological equipment of surface and underground placement for injection of fl uid carbon dioxide can be attributed the system of its capture, purifi cation, storage tanks, compressor and / or pumping stations. The article recommends rational ways to increase the effi ciency of carbon dioxide capture and injection of carbon dioxide into the well space, as well as the choice of hardware for these purposes, based on a systematic analysis of literature data, staged pilot series and industrial testing of options for solving these problems. Realization of the gas method of oil production growth will lead to several-fold increase in production. The recommended technology will make it possible to improve environmental safety by isolating the emission of CO2 emitted in the oil industry. From the economic point of view the low cost of carbon dioxide, its recycling, possibility of realization at any stage of fi eld operation, high quality parameters of marketable oil feedstock are attractive.

A mathematical model of formation of carbon dioxide gas hydrate upon injection of warm carbon dioxide into a natural stratum saturated with methane and methane hydrate has been presented. The case when methane hydrate decomposes into gas and water on two frontal boundaries and the subsequent formation of carbon dioxide hydrate from carbon dioxide and water has been discussed. The regions where this mode is implemented depending on stratum permeability have been studied based on the pressure–temperature plane of the gas being injected into the stratum.

Carbon dioxide (CO2) injection is one of the most applied enhanced oil recovery methods in the hydrocarbon industry, since it has the potential to increase oil recovery significantly and can help reduce greenhouse gases through carbon storage in hydrocarbon reservoirs. Carbon dioxide injection has a severe drawback, however, since it induces asphaltene precipitation by disrupting the asphaltene stability in crude oil that bears even the slightest asphaltene concentration. This can result in severe operational problems, such as reservoir pore plugging and wellbore plugging. This research investigates some of the main factors that impact asphaltene stability in crude oil during CO2 injection. Initially, asphaltene precipitation, flocculation, and deposition were tested using visual tests without CO2 in order to evaluate the effect of oil viscosity and temperature on asphaltene stability and content in the crude oil. The results obtained from the visualization experiments were correlated to the Yen–Mullins asphaltene model and were used to select the proper chemical to alter the oil’s viscosity without strongly affecting asphaltene stability. After performing the visual asphaltene tests, a specially designed filtration vessel was used to perform the oil filtration experiments using filter membranes with a micron and nanometer pore size. The effect of varying CO2 injection pressure, oil viscosity, filter membrane pore size, and filter membrane thickness on asphaltene stability in crude oil was investigated. The results were then correlated with the Yen–Mullins asphaltene model to characterize the asphaltene size within the oil as well. Results showed that as the oil viscosity increased, the asphaltene concentration in the oil also increased. Also, the asphaltene concentration and filter cake thickness increased with the decrease in filter membrane pore size, since the asphaltene particles either plugged up the smaller pores, or the asphaltene nanoaggregates were larger than the pore sizes, and thus the majority of them could not pass. This research studies asphaltene instability in crude oil during CO2 injection in different pore sizes, and correlates the results to the principle of the Yen–Mullins model for asphaltenes. The results from this research can help emphasize the factors that will impact asphaltene stability during CO2 injection in different pore sizes in order to help reduce asphaltene-related problems that arise during CO2 injection in hydrocarbon reservoirs.

Chapter 9 - Carbon dioxide injection in tight oil reservoirs

Based on a detailed investigation of the geological setting of coalbed methane by previous work in the Xiangzhong Depression, Hunan Province, numerical simulation methods were used to simulate the geological storage of carbon dioxide and displacement gas production in this area. In this simulation, a 400 m × 400 m square well group was constructed for coalbed methane production, and a carbon dioxide injection well was arranged in the center of the well group. Injection storage and displacement gas production simulations were carried out under the conditions of original permeability and 1 mD permeability. At the initial permeability (0.01 mD), carbon dioxide is difficult to inject, and the production of displaced and non-displaced coalbed methane is low. During the 25-year injection process, the reservoir pressure only increased by 7 MPa, and it is difficult to reach the formation fracture pressure. When the permeability reaches 1 mD, the carbon dioxide injection displacement rate can reach 4000 m3/d; the cumulative production of displaced and non-displaced coalbed methane is 7.83 × 106 m3 and 9.56 × 105 m3, respectively, and the average daily production is 1430 m3/d and 175 m3/d. The displacement effect is significantly improved compared to the original permeability. In the later storage stage, the carbon dioxide injection rate can reach 8000 m3/d, reaching the formation rupture pressure after 3 years, and the cumulative carbon dioxide injection volume is 1.17 × 107 m3. This research indicates that permeability has a great impact on carbon dioxide geological storage. During the carbon dioxide injection process, selecting areas with high permeability and choosing appropriate reservoir transformation measures to enhance permeability are key factors in increasing the amount of carbon dioxide injected into the area.

Carbon dioxide injection will induce fracture network. Carbon dioxide will reach a supercritical state under tight reservoir temperatures and pressures. During prolonged carbon dioxide injection, fracture network will extend directionally or even connect to production wells causing gas breakthroughs. Numerical simulations demonstrate that the induced fracture network will affect carbon dioxide utilization and reduce carbon dioxide storage efficiency. Therefore, the identification and efficient utilization of dynamic induced fracture network is necessary. Carbon dioxide injection will induce fracture network. Carbon dioxide will reach a supercritical state under tight reservoir temperatures and pressures. During prolonged carbon dioxide injection, fracture network will extend directionally or even connect to production wells causing gas breakthroughs. Numerical simulations demonstrate that the induced fracture network will affect carbon dioxide utilization and reduce carbon dioxide storage efficiency. Therefore, the identification and efficient utilization of dynamic induced fracture network is necessary. Results demonstrate that tri-radial flow with micro-stepped characteristic, fracture storage with V-shape characteristic, and dynamic fracture network flow with peak-shape characteristic regimes are shown in type curve. Innovation parameters—fracture inter-porosity flow coefficient (ω), dynamic fracture network conductivity (Fdf), and dynamic fracture network radius (rdf) are introduced the DIFN model. Numerical simulations verified the accuracy of the DIFN model. Multi-temporal field cases from the same well are matched by the DIFN model. The physical processes of dynamic induced fracture network expansion are characterized. It is worth noting that the innovative parameters can be used to calculate carbon dioxide fracture storage volume. By coupling the injection parameters, the carbon dioxide physical properties parameters, and the fracture storage volume we will obtain the tight reservoir carbon dioxide storage volume to monitor carbon dioxide storage efficiency in real time. In conclusion, different from the conventional view the supercritical carbon dioxide induced dynamic fracture network will form a circular zone in the near-well area. The dynamic induced fracture network will extend in the maximum principal stress direction to form an elliptical area. The identification of dynamic induced fracture network characteristics helps guide researchers to set reasonable injection parameters and assess carbon dioxide storage efficiency. The supercritical carbon dioxide induced dynamic fracture network is identified and its physical processes can be described by matching multi-temporal field cases using the DIFN model. The innovative flow regimes demonstrate the directional extension and closure of the fracture network preventing them from being identified as incorrect data. Innovative parameters are used to characterize the induced dynamic fracture network and to calculate the carbon dioxide storage volume and storage efficiency.