Improved regenerator performance by carbon dioxide injection

We are trying to develop a methane-producing system using indigenous microbes in depleted oil fields as a new microbial enhanced oil recovery process. In particular, we aim to combine a microbial conversion of the residual oil into methane with the geological sequestration of carbon dioxide. The mechanism is as follows: Hydrocarbon-degrading bacteria are harnessed to produce hydrogen and/or acetate from residual oil in the depleted oil reservoir. Then, methane-producing microbes (methanogens) utilize the produced acetate or hydrogen and carbon dioxide, which is injected for geological sequestration, to generate methane. We successfully isolated hydrogen- and methane-producing microbes (hydrogen-producing bacteria and methanogens) from oil fields (Yabase and other oil fields) in Japan. Our analysis of microbial cultures incubated under high temperature and high pressure, the condition similar to in situ petroleum reservoir conditions, revealed that indigenous microbes in the reservoir brine are capable of generating methane by utilizing crude oil and carbon dioxide. Consumption/production rate of gases (methane and carbon dioxide) and acetic acid indicated that the methane production under reservoir conditions is likely mediated through two major pathways; the acetoclastic (acetic-acid utilizing) and the hydrogenotrophic (hydrogen and carbon-dioxide utilizing) pathways. Furthermore, by analyzing methane-producing ability of isolated microbes, we found that the syntrophic cooperation between hydrogen-producing bacteria and methanogens was critical for the methane producing under the reservoir condition. 0%.tures with carbon dioxideent Strikingly, addition of carbon dioxide accelerated methane production of the cultures. The methane production rate of the cultures, in which high concentration (10%) of carbon dioxide was supplied into the head spaces, was 0.30 mmol/L/Day. On the other hand, the cultures without the addition of carbon dioxide showed the methane production rate of 0.12 mmol/L/Day, significantly slower (ca. 40%) than the production rate of the cultures with carbon dioxide. These results suggested that addition (injection) of carbon dioxide into reservoirs might accelerate the microbial methane production. We further investigated the methanogenic communities and pathways in petroleum reservoirs by incubating the reservoir brine from the Yabase oil field, combined with radiotracer experiments and molecular biological analyses. The brine samples were incubated without exogenous-nutrient supplementation under the high-temperature and high-pressure condition (the in-reservoir condition). The radiotracer analysis (using 14C-biocarbonate and 14C-acetate) indicated that the methane production rate of hydrogenotrophic methanogenesis was 50-fold higher than that of acetoclastic methanogenesis, suggesting dominance of methane production by syntrophic acetate oxidation coupled with hydrogenotrophic methanogenesis in reservoir. In this study, we assessed the rate of oil biodegradation coupled with methanogenesis by using 14C-labeled toluene and hexadecane as tracers. The analysis revealed that the rate was very low, being only about one thousandth of that of the hydrogenotrophic methanogenesis. We are currently trying to enhance the crude-oil biodegradation for effective conversion of crude oil to methane. Our goal is to establish effective microbial conversion system from residual oil into methane in depleted oil fields as a new EOR technology.

The process of carbonaceous materials gasification is especially relevant in Russia, where the volume of coal waste exceeds 120 million tons. A gasification installation for carbon-containing waste operating in the fixed-bed mode has been developed. Experiments on gasification of fine coal fraction samples (1–2 mm) were carried out using preheated air, a steam-air mixture, and air with added carbon dioxide as gasifying agents. The work used the methods of differential scanning calorimetry, thermogravimetric analysis, and chromatographic analysis. Additions of water vapor and carbon dioxide made it possible to increase the heat of combustion and increase the gasification efficiency to 54%. The operating mode of the gas generator was determined, ensuring the production of synthesis gas with a calorific value of 3.6 MJ/nm3. It is shown that the highest efficiency of gas generation is achieved in the steam-air gasification mode with the addition of water vapor in the amount of 0.1 kg per 1 kg of coal and with the use of air as a gasifying agent with the addition of carbon dioxide in a volume ratio of 100:5. It is established that an increase in the addition of water vapor and carbon dioxide above the optimal amounts leads to a decrease in the efficiency of the gasification process. The process can use waste from various industries, including oil sludge, which determines its significance for the effective management of carbon-containing waste and for achieving broader environmental and economic goals.

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

Chapter 9 - Carbon dioxide injection in tight oil reservoirs

Effects of simultaneous hydrogen enrichment and carbon dioxide dilution of fuel on soot formation in an axisymmetric coflow laminar ethylene/air diffusion flame

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

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

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

Excessive emissions of greenhouse gases, such as carbon dioxide, can cause severe global climatic changes, which may include an increase in the global temperature, rise of the sea level, increase in wildfire, floods, and storms, in addition to changes in the amount of rain and snow. The global mitigation strategies that can be envisioned to reduce the release of greenhouse gas emissions to the atmosphere include retrofitting buildings with more energy-efficient systems, increasing the dependency on renewable energy sources in lieu of fossil fuels, increasing the use of sustainable transportation systems that rely on electricity and biofuels, and adopting globally more sustainable uses of land and forests. To reduce global climatic changes, the excess amount of carbon dioxide in the environment needs to be captured and stored in deep underground sedimentary reservoirs. The sedimentary reservoirs that contain water in the rock matrix provide a more secure CO2 sequestration medium. The injection of carbon dioxide causes a huge increase in the reservoir pore pressure and provokes the subsequent ground uplift. The excessive increase in pore pressure may also cause leakage of carbon dioxide into the potable water layers and to the atmosphere, thus leading to severe global climatic changes. In order to maintain the integrity of the sequestration process, it is crucial to inject a safe quantity of carbon dioxide into the sequestration site. Accordingly, the injection period and the safe values of injection parameters, like flow rate and injection pressure, need to be calculated a priori to ensure that the stored carbon dioxide will not leak into the atmosphere and jeopardize the climate mitigation strategy. To model carbon dioxide injection in reservoirs having a base fluid, such as water, one has to perform a two-phase flow modeling for both the injected and base fluids. In the present investigation, carbon dioxide is injected into Biyadh reservoir, wherein the two-phase flow through the reservoir structure is taken into account. This investigation aims to estimate the safe parameter values for carbon dioxide injection into the Biyadh reservoir, in order to avoid leakage of carbon dioxide through the caprock. In this context, the two cases of a fractured and non-fractured caprock are considered. To ensure a safe sequestration mechanism, the coupled reservoir stability analysis is performed to estimate the safe values of the injection parameters, thus furnishing data for a reliable global climate change mitigation strategy. The obtained results demonstrated that the injection of carbon dioxide has caused a maximum pore pressure increase of 25 MPa and a ground uplift of 35 mm.

This study invest0igated the effect of CO2 added to achieve three pH levels: pH 6.1, pH 6.2 and pH 6.3 for treatments X, Y, Z, respectively, on some microbiological properties of Turkish White (TW) brined cheese. For each pH, four batches of cheese were produced from: raw milk with no added carbon dioxide (UR), raw milk with carbon dioxide (TR), pasteurised milk with no carbon dioxide addition (UP) and pasteurised milk with carbon dioxide addition (TP). The microbiological analysis of TW brined cheeses was carried out for 90 days of maturation period. Total aerobic mesophilic bacteria, mesophilic lactic acid bacteria, yeasts and moulds and coliform group were determined in control and CO2 treatment groups. Mesophilic bacteria count was determined as 5.14, 5.29, 5.67 log cfu/g for pH 6.1, 6.2 and 6.3, respectively, in CO2‐treated raw milk cheeses. Yeasts and moulds reduction increased significantly by applying CO2 (P < 0.01). For TW cheese samples, the most significant microbial inactivation was detected at sample groups of pH 6.1.

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.

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

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.

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.

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.