Flue gas injection into gas hydrate reservoirs for methane recovery and carbon dioxide sequestration (original) (raw)
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Day 4 Fri, March 23, 2018, 2018
Because CO2 hydrate is stable at pressures lower than those required to stabilize hydrates of CH4 when compared at the same temperature the injection of CO2 into gas hydrate reservoirs was proposed a while ago as a method to recover methane. The added advantage of such a technology is the simultaneous sequestering/storage of CO2 captured from fossil fuel power plants or other significant point sources of CO2. Recent reviews on the subject have provided an account of the laboratory and theoretical work on this topic. The reviews highlighted the need to further elucidate the dynamics of the exchange process and provide information needed for the design of industrial scale facilities. In this work, the kinetics of the CO2/CH4 exchange process are investigated in a 5.3 L laboratory crystallizer (reservoir) equipped with ahorizontal injection tube with 24 exits into the packed bed of silica sand particles. Preliminary experiments conducted using this apparatus and also with a high pressu...
Scientific Reports
Large hydrate reservoirs in the Arctic regions could provide great potentials for recovery of methane and geological storage of CO2. In this study, injection of flue gas into permafrost gas hydrates reservoirs has been studied in order to evaluate its use in energy recovery and CO2 sequestration based on the premise that it could significantly lower costs relative to other technologies available today. We have carried out a series of real-time scale experiments under realistic conditions at temperatures between 261.2 and 284.2 K and at optimum pressures defined in our previous work, in order to characterize the kinetics of the process and evaluate efficiency. Results show that the kinetics of methane release from methane hydrate and CO2 extracted from flue gas strongly depend on hydrate reservoir temperatures. The experiment at 261.2 K yielded a capture of 81.9% CO2 present in the injected flue gas, and an increase in the CH4 concentration in the gas phase up to 60.7 mol%, 93.3 mol%...
2007
Although recent estimates (MILKOV et al., 2003) put the global accumulations of natural gas hydrate at 3,000 to 5,000 trillion cubic meters (TCM), compared against 440 TCM estimated (COLLETT, 2004) for conventional natural gas accumulations, how much gas could be produced from these vast natural gas hydrate deposits remains speculative. What is needed to convert these gas-hydrate accumulations to recoverable reserves are technological innovations, sparked through sustained scientific research and development. As with other unconventional energy resources, the challenge is to first understand the resource, its coupled thermodynamic and transport properties, and then address production challenges. Carbon dioxide sequestration coupled with hydrocarbon resource recovery is often economically attractive. Use of CO 2 for enhanced recovery of oil, conventional natural gas, and coal-bed methane are in various stages of common practice. In this report, we discuss a new technique utilizing CO 2 for enhanced recovery of natural gas hydrate. We have focused our attention on the Alaska North Slope where approximately 640 Tcf of natural gas reserves in the form of gas hydrate have been identified. Alaska is also unique in that potential future CO 2 sources are nearby, and petroleum infrastructure exists or is being planned that could bring the produced gas to market or for use locally.
2014
The injection of CO 2 into CH 4-hydrate-bearing sediments has the potential to drive natural gas production and simultaneously sequester CO 2 by hydrate conversion. Currently, process conditions under which this goal can be achieved efficiently are largely unknown. While the recent Ignik Sikumi field test suggests that a combination of N 2 /CO 2 injection with depressurization yields effective CH 4 production, in a previous study (Deusner et al., 2012) we showed that a combination of CO 2 injection and thermal stimulation eliminates mass transfer limitations observed at cold reservoir temperatures. These highpressure flow-through studies revealed that the injection of supercritical CO 2 at 95 °C triggers dissociation of CH 4-hydrates and counters rapid CO 2-hydrate formation in the near-injection region. We also observed a strong effect of reservoir temperature on CH 4 production and CO 2 retention. The efficiency and yield of CH 4 production was highest at a sediment temperature of 8 °C compared to 2 °C and 10 °C. At 2 °C CO 2 hydrate formation was rapid and clogged the sediment at the injection spot. Outside the CO 2-hydrate stability region, at 10 °C, we observed fast CO 2 breakthrough and a comparably low CH 4 production. Experiments comparing discontinuous and continuous CO 2 injection showed that alternating periods of equilibration and CO 2 injection improved the overall CH 4 production. We hypothesize that slow formation of secondary CO 2-rich hydrate improves the accessibility of the CH 4-hydrate distributed in the sediment by locally changing permeability and fluid flow patterns. In situ measurements showed dynamic changes of local p-/T-gradients due to gas hydrate dissociation or dissolution and secondary gas hydrate formation. In addition, continued reconfiguration of guest molecules in transiently formed mixed hydrates maintain elevated gas exchange kinetics. Online effluent fluid analysis under in-situ pressure conditions indicated that CH 4 released from CH 4-hydrates is largely dissolved in liquid CO 2 .. It is a current objective of our studies to further elucidate rheological properties and gas exchange efficiencies of CO 2-CH 4 mixed fluids that approach equilibrium with gas hydrates and to study the effect of in situ CH 4-CO 2-hydrate conversion and secondary gas hydrate formation on sediment geomechanical parameters.
Energy & Fuels, 2018
Class 2 hydrate accumulations are characterized by the presence of an aquifer underneath hydrate bearing sediment. Gas extraction from of these hydrate deposits is accompanied with release of large volumes of water that decreases gas production rates, imposes additional load on the lifting system, and, as a result, degrades economical attractiveness of possible exploitation sites. This work studies enhanced methane production from Class 2 hydrate accumulations using the CO 2-assisted technique where the aquifer serves as a target zone for CO 2 injection. The heat release associated with the CO 2 hydrate formation and reduction of the aquifer's permeability benefit the subsequent decomposition of the overlying methane hydrate. The new production technique includes three stages utilizing one vertical well, which serves as an injector during the first stage and as a producer in the third stage. First, the CO 2 is injected into the underlying aquifer, then the well is shut down and injected CO 2 is converted into hydrate during the second stage. In the third stage, decomposition of CH 4 hydrate is induced by the depressurization method to estimate gas production potential over 15 years. The results reveal that methane production is increased together with simultaneous reduction of concomitant water production comparing to production from the Class 2 reservoir using only conventional depressurization.
Recovery of Methane from Hydrate Formed in a Variable Volume Bed of Silica Sand Particles
Energy & Fuels, 2009
The decomposition of methane hydrate crystals formed in sediment at 1.0, 4.0, and 7.0°C was studied in a new apparatus designed to accommodate three different size volume beds of silica sand particles. The sand particles are microporous with a 0.9 nm pore diameter and have an average diameter equal to 329 μm. The hydrate was formed in the interstitial spaces between sand particles, and the hydrate crystal decomposition was driven by heating (thermal stimulation). The amount of methane released from the dissociating hydrate in each experiment (methane recovery curve) was determined, and it was shown that the release of gas proceeds in two stages in terms of rate. The rate of methane release (recovery) per mole of water depends on the bed size for the first stage of hydrate dissociation. The second stage rate does not depend on the bed size. This work suggests that the comparison of simulated data to experimental results from laboratory synthesized hydrate and possibly from natural samples should be done with more than one sample-size data.
Coal Mine Methane Gas Recovery by Hydrate Formation in a Fixed Bed of Silica Sand Particles
Energy & Fuels, 2013
In the present work, the separation of CH 4 from low-concentration coal mine methane gas (30 mol % CH 4 /N 2 ) through hydrate crystallization was investigated in a fixed bed of silica sand particles. The influence of the additive tetrahydrofuran (THF) on hydrate equilibrium conditions and kinetics of CH 4 separation was studied as well. The incipient hydrate equilibrium conditions at 1 mol % THF were determined using the isothermal pressure search method. It was found that the presence of THF significantly reduced the hydrate equilibrium conditions as compared to those obtained in liquid water with the same gas mixture. CH 4 recovery in the water-saturated silica sand bed was considerably low (∼12.0%) because N 2 molecules might compete with CH 4 molecules to enter the hydrate crystals under high pressure conditions. The addition of THF to the bed of silica sand particles reduced the nucleation time of gas hydrate formed from the 30 mol % CH 4 /N 2 gas and increased the CH 4 recovery (∼21.4%) significantly. The comparison of CH 4 separation between the silica sand bed and the stirred reactor in the presence of THF indicated that CH 4 recovery was approximately the same, but the conversion of water to hydrate in the THF solution-saturated silica sand bed was largely increased.
Gas hydrate formation rates from dissolved-phase methane in porous laboratory specimens
Geophysical Research Letters, 2013
1] Marine sands highly saturated with gas hydrates are potential energy resources, likely forming from methane dissolved in pore water. Laboratory fabrication of gas hydrate-bearing sands formed from dissolved-phase methane usually requires 1-2 months to attain the high hydrate saturations characteristic of naturally occurring energy resource targets. A series of gas hydrate formation tests, in which methane-supersaturated water circulates through 100, 240, and 200,000 cm 3 vessels containing glass beads or unconsolidated sand, show that the rate-limiting step is dissolving gaseous-phase methane into the circulating water to form methane-supersaturated fluid. This implies that laboratory and natural hydrate formation rates are primarily limited by methane availability. Developing effective techniques for dissolving gaseous methane into water will increase formation rates above our observed (1 ± 0.5) × 10 À7 mol of methane consumed for hydrate formation per minute per cubic centimeter of pore space, which corresponds to a hydrate saturation increase of 2 ± 1% per day, regardless of specimen size. Citation: Waite, W. F., and E. Spangenberg (2013), Gas hydrate formation rates from dissolved-phase methane in porous laboratory specimens, Geophys.
Numerical simulations for enhanced methane recovery from gas hydrate accumulations by utilizing CO2 sequestration Prathyusha Sridhara In 2013, the International Energy Outlook (EIA, 2013) projected that global energy demand will grow by 56% between 2010 and 2040. Despite strong growth in renewable energy supplies, much of this growth is expected to be met by fossil fuels. Concerns ranging from greenhouse gas emissions and energy security are spawning new interests for other sources of energy including renewable and unconventional fossil fuel such as shale gas and oil as well as gas hydrates. The production methods as well as long-term reservoir behavior of gas hydrate deposits have been under extensive investigation. Reservoir simulators can be used to predict the production potentials of hydrate formations and to determine which technique results in enhanced gas recovery. In this work, a new simulation tool, Mix3HydrateResSim (Mix3HRS), which accounts for complex thermodynamics of multi-component hydrate phase comprised of varying hydrate solid crystal structure, is used to perform the CO2-assisted production technique simulations from CH4 hydrate accumulations. The simulator is one among very few reservoir simulators which can simulate the process of CH4 substitution by CO2 (and N2) in the hydrate lattice. Natural gas hydrate deposits around the globe are categorized into three different classes based on the characteristics of the geological sediments present in contact with the hydrate bearing deposits. Amongst these, the Class 2 hydrate accumulations predominantly confirmed in the permafrost and along seashore, are characterized by a mobile aqueous phase underneath a hydrate bearing sediment. The exploitation of such gas hydrate deposits results in release of large amounts of water due to the presence of permeable water-saturated sediments encompassing the hydrate deposits, thus lowering the produced gas rates. In this study, a suite of numerical simulation scenarios with varied complexity are considered which aimed at understanding the underlying changes in physical, thermodynamic and transport properties with change in pressure and temperature due to the presence of the simple CO2-hydrate and mixed hydrates (mainly CH4-CO2 hydrate and CH4-CO2-N2 hydrate) in the porous geologic media. These simulations on CO2/ CH4-CO2 hydrate reservoirs provided a basic insight to formulate and interpret a novel technological approach. iii Dedicated to my parents iv Acknowledgement First and foremost, I'd like to express my deepest gratitude to Sri Ganapathi Sachchidananda Swamiji for His divine blessings and insightful messages. "Patience and perseverance are crucial for success"-this has been one of the most influential sayings of His on me and helped me to become goal-oriented. I'd like to express my deepest gratitude to my research advisor, Dr. Brian Anderson for his constant support, remarkable guidance and encouragement. He has set himself as an example and shown me what a good scientist (and person) should be. I am also immensely indebted to Dr. Evgeniy Myshakin for his motivation and comprehensive advices throughout the research work. Their suggestions helped me to learn a great deal about scientific research and life in general. I'd like to thank Department of Chemical Engineering at WVU and also everyone in my dissertation committee members for their valuable suggestions and for providing unending inspiration. I am immensely grateful to West Virginia University for providing me an opportunity to pursue my doctoral studies here in Morgantown. It also gave me a chance to explore the "wild and wonderful", and I take immense pleasure and pride in referring it as my second home and being a Mountaineer, I learnt from the people around here, that being kind and generous is an important virtue one should abide.