Flue gas injection into gas hydrate reservoirs for methane recovery and carbon dioxide sequestration (original) (raw)
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.
Journal of Petroleum Science and Engineering, 2019
In this paper, characteristics of gas permeation through gas hydrate-bearing sediments were explored under varying differential pressure for three types of sedimentary core samples, including 100 wt. % silica sand, 95 wt. % silica sand + 5 wt. % montmorillonite clay, and consolidated sandstone using a standard coreholder. Results of the experiments indicate that capillary breakthrough, hydrateforced heave or agglomeration and also Klinkenberg effect play important roles in controlling the gas permeation through different porous sediments, depending on the sediment type and properties such as grain/pore size distribution and degree of consolidation. It was observed that due to the presence of large pores in unconsolidated silica sand core samples, the gas flow is dominated at both hydratefree and hydrate-bearing cases by the capillary breakthrough mechanism rather than the gas slippage which resulted in direct relationship between the gas permeability and the differential pressure. This mechanism was also observed to be dominant while measuring the gas permeability for the hydrate-free sandstone core sample. For the unconsolidated sand-clay core samples, higher saturation of methane hydrate led to relatively higher gas permeability due to hydrate-forced heave phenomenon which pushed the sediment grains apart from each other or hydrate agglomeration that formed inter-grain pores. Klinkenberg effect became significant for the hydrate-free sand-clay and hydrate-bearing sandstone core samples; however, it was not observed to be dominant in the hydrate-bearing sand-clay core samples due to the hydrate-forced heave and agglomeration until the inlet pressure was sufficiently high.
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.
The Journal of Chemical Thermodynamics, 2018
Enhanced depressurisation for methane recovery from gas hydrate-bearing sediments was experimentally studied by injection of compressed air and nitrogen. Experiments were conducted in simulated sediments (silica sand) from 273.4 K to 283.0 K and initial system pressures ranging from 3.8 MPa to 7.2 MPa before air or nitrogen injection. The results show that injection of air and nitrogen made it possible to implement conventional depressurisation in multiple stages. In each pressure stage, methane hydrate was quickly dissociated by the injected air or nitrogen due to direct shift of the methane hydrate equilibrium phase boundary. Methane hydrate dissociation at high pressures enables methane recovery inside the methane hydrate stability zone. Depressurisation well above the methane hydrate dissociation pressure generated a methane-rich gas phase of up to 90 mol% methane depending on the injected gas. Injection of compressed air or nitrogen provides a potential approach to improve the technical feasibility and economic viability of conventional depressurisation method for methane recovery from most gas hydrate reservoirs with severe conditions such as low permeability or dispersed hydrates.
ACS Sustainable Chemistry & Engineering, 2019
The climate system is changing globally, and there is substantial evidence that subsea permafrost and gas hydrate reservoirs are melting in high-latitude regions of the Earth, resulting in large volumes of CO2 (from organic carbon deposits) and CH4 (from gas hydrate reserves) venting into the atmosphere. Here, we propose the formation of flue gas hydrates in permafrost regions and marine sediments for both the geological storage of CO2 and the secondary sealing of CH4/CO2 release in one simple process, which could greatly reduce the cost of CO2 capture and storage (CCS). The kinetics of flue gas hydrate formation inside frozen and unfrozen sediments were investigated under realistic conditions using a highly accurate method and a well-characterized system. The results are detailed over a wide range of temperatures and different pressures at in situ time scales. It has been found that more than 92 mol% of the CO2 present in the injected flue gas could be captured under certain conditions. The effect of different relevant parameters on the kinetics of hydrate formation has been discussed, and compelling evidence for crystal-structure changes at high pressures has been observed. It has also been found that temperature rise leads to the release of N2 first, with the retention of CO2 in hydrates, which provides a secondary safety factor for stored CO2 in the event of a sudden temperature increase.
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.