CH4 Recovery Research Articles

Influence of the initial CH4-hydrate system properties on CO2 capture kinetics

Recovering methane from natural gas hydrate deposits using carbon dioxide injection is currently of great environmental and energetic interest as it shows potential for producing an energy resource while mitigating CO2 emissions through CO2 sequestration. This work investigates the exchange kinetic between CH4 and CO2 (or CO2-N2(v)) in synthetic hydrates, with an emphasis on the impact of CH4 hydrate formation conditions (e.g. driving force Δp) on the subsequent exchange reactions. Different driving forces Δp are utilized and show that the exchange kinetic is improved by a factor of ~3 when the exchange is performed with low Δp CH4 hydrates, for which there is a higher relative amount of free H2O(liq) (277 K); the kinetic is further improved when stirring is applied. Isobaric CH4 hydrates exhibit a fast primary hydrate dissociation and CH4 release, followed by a slower exchange kinetic, possibly limited by solid-state exchange diffusion or secondary CO2-rich hydrate formation within the stability field of CH4 hydrates. Upon exposure to a mixed CO2-N2(v) gas stream, secondary hydrate production is governed by the effective Δp remaining after dissolution of the gas mixture, and results in an even slower exchange reaction rate. These results may help optimizing recovery processes in field trial experiments, where both hydrates and liquid water coexist, and aid in predicting the risk of geo-hazards induced by unstable secondary hydrate formation. Furthermore, the exchange kinetic dependencies highlighted here are important as they affect the overall energy efficiency and energy cost of CH4 recovery processes in gas hydrate field trials.

The Utility of Purge and Recovery Testing in Ground-Gas Flux Risk Assessment

Purge and recovery testing is a novel method for measuring ground-gas flux. This method has been tested with Gasclam in boreholes at two landfill sites. The recovery rate of individual gases was used to predict when and at what concentration they would reach the unmonitored receptors. For example, at site 1 in borehole 2, CH4 and CO2 had concentrations of 22 % and 4 % respectively before purging in September 2010 and, 23 % and 4.4 % respectively in May 2011 before purging. While 22 % of CH4 and 4 % of CO2 were recovered in 32 hrs and 14 hrs respectively after purging, 23 % of CH4 and 4.4 % of CO2 were recovered in 52 hrs and 27 hrs respectively after purging. This implies that CH4 and CO2 concentrations recovery in this borehole was faster in September 2010 than in May 2011. The recovery time of the investigated gases [CH4, CO2 and Volatile Organic Compounds (VOC)] varied from the length of site visit to over a day. It also varied with season and site. Soil permeability and gas production rate are suspected to be responsible for variations in gas recharge rate. In general, the recovery profiles of VOC were very different from those of CH4 and CO2. VOC tended to recover in no time, indicating that they could get to the receptor much faster compared to other gases, thereby posing more danger. The reproducibility of the gases was not consistent due to their low concentrations.

The Utility of Purge and Recovery Testing in Ground-Gas Flux Risk Assessment

Purge and recovery testing is a novel method for measuring ground-gas flux. This method has been tested with Gasclam in boreholes at two landfill sites. The recovery rate of individual gases was used to predict when and at what concentration they would reach the unmonitored receptors. For example, at site 1 in borehole 2, CH4 and CO2 had concentrations of 22 % and 4 % respectively before purging in September 2010 and, 23 % and 4.4 % respectively in May 2011 before purging. While 22 % of CH4 and 4 % of CO2 were recovered in 32 hrs and 14 hrs respectively after purging, 23 % of CH4 and 4.4 % of CO2 were recovered in 52 hrs and 27 hrs respectively after purging. This implies that CH4 and CO2 concentrations recovery in this borehole was faster in September 2010 than in May 2011. The recovery time of the investigated gases [CH4, CO2 and Volatile Organic Compounds (VOC)] varied from the length of site visit to over a day. It also varied with season and site. Soil permeability and gas production rate are suspected to be responsible for variations in gas recharge rate. In general, the recovery profiles of VOC were very different from those of CH4 and CO2. VOC tended to recover in no time, indicating that they could get to the receptor much faster compared to other gases, thereby posing more danger. The reproducibility of the gases was not consistent due to their low concentrations.

Liquid CO2 injection to enhance coalbed methane recovery: An experiment and in-situ application test

In recent times, enhanced deep-buried coalbed methane recovery has increased the interest in coal and unconventional natural gas exploration. This study investigated liquid CO2 (LCO2) injection to enhance coalbed methane recovery, the variation in the gas component and the sweep efficiency of CH4 recovery by LCO2 injection into coal were studied under laboratory conditions. The results demonstrated that the rate of decrease in CH4 concentration initially increased and then stabilized with the increase in the injection pressure of LCO2. This investigation revealed two factors behind the decrease in the CH4 concentration. The first was the carrying effect of CO2 airflow and the competitive adsorption between CO2 and CH4 that enhanced CH4 recovery in coal, while the second was the dilution effect of high-concentration CO2 that diluted the residual CH4 molecules and the experiment converted into an inefficient stage. Additionally, the quantitatively calculated results indicated that the average sweep efficiency of CH4 recovery was greater than 92.0%, which proves the sweep efficiency of CH4 recovery by low-pressure LCO2 injection was obvious. An in-situ test of high-gas-content coalbed in Chinese mining areas concluded that the effective migration radius of CO2 in the test coalbed was beyond 15 m when the cumulative LCO2 injection volume was approximately 5.0 m3. The amount of methane extraction was compared with that obtained by the original gas extraction for 60 consecutive days, the amount of methane extracted from the test coalbed was 2–3 times higher and the time taken for methane extraction to reach the standard was significantly reduced.

Study of CO2 Enhancing Shale Gas Recovery Based on Competitive Adsorption Theory.

As an indispensable part of unconventional natural gas resources, the shale reservoir is huge and widely distributed. It is of great significance to study how to enhance the shale gas recovery for improving the energy structure. In order to solve the problem of low gas production rate and long recovery period in the process of shale gas production, in this paper, the influences of pressure, temperature, moisture, and gas type on isothermal adsorption and desorption of shale gas are analyzed based on shale adsorption and desorption experiments, and the adsorption and desorption abilities of CO2 and CH4 in shale are compared to verify the feasibility of CO2 enhancing shale gas recovery. Depletion production experiments and CO2 injection experiments with different injection pressures (6 and 7 MPa), different injection rates (5, 10 and 20 mL/min), and different injection amounts are carried out. The mechanism of CO2 enhancing shale gas recovery is proposed, and the parameters of CO2 injection are optimized. The results show that the adsorption capacity of CH4 increases with the increase in pressure and the decrease in temperature and moisture in a certain range. Under the same experimental conditions, the sorting of adsorption capacity is CO2 > CH4 > N2, while desorption capacity is CH4 > CO2 > N2. The desorption curves of the three gases lag behind the adsorption curves, in which the lag phenomenon of CO2 is most obvious. The ultimate recovery of depletion production ranges from 66 to 73%. CO2 injection can effectively increase the gas production rate of CH4, and it can also keep the cumulative gas production of CH4 growing steadily and rapidly. Within a certain range, CH4 recovery increases with the increase in CO2 injection pressure, the injection rate, and injection amount, but its increase range is related to the porosity and permeability of shale.

Quantitative experimental investigation of CO2 enhancement of the desorption rate of adsorbed CH4 in coal

The injection of CO2 into a coal seam can effectively improve the recovery efficiency of coalbed methane. Existing CO2-enhanced coalbed methane(ECBM) is mainly focused on improving the physical recovery efficiency of free CH4. In macro experiments, it is difficult to simultaneously separate adsorbed CH4 and free CH4; therefore, there are few studies on using CO2 to improve the recovery efficiency of coal seams. In this study, the LF-NMR method was used to evaluate the transformation law of adsorbed and free CH4 during the CO2 injection process, and the enhancement of adsorbed CH4 recovery efficiency using CO2 was quantified. The results showed that adsorbed CH4 and free CH4 formed separate T2 peaks, allowing them to be distinguished. The T2 spectra of adsorbed CH4 (adsorbed on pore surfaces) were distributed between 0.01 and 2.247806 ms, whereas the T2 spectrum of free CH4 (existing between the coal particles and the inner walls of sample cavities) were distributed between 15.702901 and 714.942899 ms. CO2 injection increased the total desorption efficiency of adsorbed CH4 by 19.89%, the desorption efficiency of adsorbed CH4 per unit time by 14.108% and the amount of CH4 desorption per unit mass of coal by 35.23%. The results of the study demonstrate that CO2 injection into a coal seam can significantly improve the recovery efficiency of adsorbed CH4 and shorten the CH4 desorption time; findings that are highly significant in relation to enhancing coalbed methane exploitation and CO2 geological storage.

Enhanced coalbed permeability and methane recovery via hydraulic slotting combined with liquid CO2 injection

Enhanced and efficient recovery of coalbed methane (CBM) is essential to prevent mine disasters and utilize unconventional gas resources. In this study, hydraulic slotting (HS) combined with liquid CO2 (LCO2) injection was employed to enhance coalbed permeability and the efficiency of methane recovery from a high-gas and low-permeability coalbed. First, mercury intrusion porosimetry and scanning electron microscopy experiments were conducted to analyze the variations in the coal microstructure and the permeability after HS combined and LCO2 freezing–thawing was conducted under laboratory conditions. The results indicated that the basic parameters of pore structures increased significantly for the treated coal; for instance, porosity and permeability increased by 47.65 % and 65.31 %, respectively. This indicated that coal permeability increased significantly under multiple stresses induced via HS and LCO2 freezing–thawing. Subsequently, a simulated experiment of LCO2 injection to enhance CH4 recovery from coal was performed; the results thus obtained revealed that LCO2 injection into a high-gas-content coalbed can enhance CBM recovery with an average efficiency of >90 %. Furthermore, an in-situ test indicated that the effective radii for HS and LCO2 injection were 2.5m and 10m, respectively. The results of a 90-d-long methane extraction revealed that the efficiency of CBM recovery increased by a factor of >2.2 and that the residual gas content in the test coalbed was <8.0m3/t after the use of HS combined with LCO2 injection. Additionally, the time required to meet methane extraction standards was reduced significantly.

Modelling competitive sorption and plasticization of glassy polymeric membranes used in biogas upgrading

A mathematical model of membrane performance is developed that incorporates fugacity-dependent permeabilities, competitive sorption, penetrant blocking and plasticization effects. The model also accounts for non-isothermal operation and includes real gas behavior and concentration polarization. Importantly, the model simultaneously considers plasticization caused by water vapor (H2O) and carbon dioxide (CO2). A simulation of biogas (composed of methane (CH4), CO2 and H2O) upgrading is performed using the new model and compared to models that use constant and pure gas permeability. Relative to these simplified models, the new model predicts differences up to 2% and 18% in CH4 recovery at low feed flowrates and the difference in CO2 removal can be as significant as 50%. Furthermore, simulations with and without water vapor in the feed give predictions that are 4.5%–34% different. The differences are attributed to the changes in fugacity-dependent permeabilities, particularly the sensitivity of these permeabilities to feed composition. An analysis indicates that the contributions of competitive sorption and penetrant blocking/plasticization to these differences is 19% and 32% in terms of CH4 recovery and CO2 removal, respectively. The remaining differences are due to real gas behavior, while concentration polarization has a negligible impact under the chosen conditions.

CH4 recovery and CO2 sequestration from hydrate-bearing clayey sediments via CO2/N2 injection

Injecting carbon dioxide (CO2) into natural gas hydrates (NGHs) to replace methane (CH4) is a prospective technique to simultaneously realise energy resource exploitation and greenhouse effect reduction. Tremendous amounts of NGHs occur in clayey reservoirs. However, the replacement of CH4 with CO2 in clayey sediments has received little attention. To study CH4 recovery from and CO2 sequestration in clayey NGH reservoirs, injection of CO2/N2 (with a molar ratio of CO2 to N2 of 1:4) into CH4 hydrate-bearing clayey sediments was experimentally researched. CH4 hydrates were formed in the sediments with different clay minerals and contents to simulate NGH clayey reservoirs. The experimental results show that gas molecule exchange between the CO2/N2 gas mixture and CH4 hydrates could occur in clayey sediments. It was found that the presence of montmorillonite in sediments had a much greater inhibition effect on CH4 recovery and CO2 sequestration than that of kaolinite or illite. In hydrate-bearing sediments with kaolinite and illite, the extent of formation of mixed hydrates was significant in the early stage of the replacement. In contrast, the strong water adsorption of montmorillonite led to the gas molecule exchange dominating the whole replacement process in the sediments. In addition, the increase of hydrate saturation resulted in the reduction of CH4 recovery efficiency in montmorillonite-bearing sediments, whereas it was conducive to CH4 recovery efficiency in hydrate-bearing sand/sandstone. These results provide theoretical support for the exploitation of NGHs in clayey reservoirs by CO2/N2 injection.

Investigation of hydrate formation by synthetic ternary gas mixture with cyclopentane(C5H10)

Cyclopentane (CP) is an alkane that combines with water to form hydrates. Here, we investigate the hydrate thermal dynamics and formation kinetics of a synthesized ternary gas mixture of CH4/CO2/N2 with CP additives. The results indicated that CP shifts the phase equilibrium conditions of ternary gas mixture hydrates to higher temperature and lower pressure. Under a constant pressure, the largest temperature offset can be approximately 20 K. Meanwhile, the ternary gas mixture of CH4/CO2/N2 formed structure II hydrates with added CP. The kinetics study indicated that the hydrate reaction started immediately when accompanied by stirring. The consumption of CO2 gas was greater than that of CH4 and N2. The ratio of the volume of CP to the volume of water had a considerable influence on the effective reaction time, CH4 recovery factor (RCH4), and CO2 split ratio (SCO2) under all experimental conditions. RCH4 and SCO2 were higher when the CP-to-water volume ratio was 0.308. The largest values of RCH4 and SCO2 were 3.098 and 0.908, respectively, when the CP-to-water volume ratio was 0.308 at 7.0 MPa and 280.1 K. These results favor the use of CP as an additive to separate CO2 and purify CH4 in gas mixtures.

Biomethane production by adsorption technology: new cycle development, adsorbent selection and process optimization

Gas separation by adsorption processes such as pressure swing adsorption (PSA) presents an attractive alternative for upgrading biogas to biomethane. A new vacuum pressure swing adsorption (VPSA) cycle is proposed for a unit designed to purify pre-cleaned biogas (40% CO2 and 60% CH4) in industrial conditions (feed flow rate more than 500 Nm3/h and large-volume equipment). The process simulations performed to optimize the VPSA unit consider the kinetic separation of the feed components by using an appropriate carbon molecular sieve (CMS) adsorbent having a high kinetic separation selectivity for CO2 with respect to CH4. The designed VPSA unit is composed of five columns that perform three equalization steps. Minimizing methane losses during the regeneration steps necessitates injecting part of the off-gas rich in CO2 at the bottom of the column during the production step to push the CH4 forward. The produced biomethane meets the specification (97% CH4) of grid injection purity. The developed cycle allows a CH4 recovery of 92% to be obtained with a specific energy consumption of 0.35 kWh/Nm3, thus meeting the initial requirements for industrial exploitation of VPSA technology for biomethane purification from biogas sources.

A generalized equation of state for associating fluids in nanopores: Application to CO2-H2O, CH4-H2O, CO2-CH4, and CO2-CH4-H2O systems and implication for extracting dissolved CH4 by CO2 injection

A modified cubic-plus-association (CPA) equation of state is presented by considering the influences of pore sizes and intermolecular interactions. Additionally, the van der Waals (vdW) mixing rule is modified to make it applicable to predicting the phase behavior of mixtures. The predictions of the CPA–vdW model are consistent with the experimental interfacial tensions of the CH4-nC10, CO2-nC10, and N2-nC10 systems in nanopores. The predictions of the CPA–vdW model for vapor–liquid equilibria of the CO2-H2O, CH4-H2O, CO2-CH4, and H2O-CH4-CO2 systems are accurate in bulk at 273.15–513.15 K and 0.1–200 MPa. The forward and backward multiple-contact processes are used to model CO2 injection to extract the dissolved CH4. The CH4 recovery factor obtained by CO2 injection is approximately 20%–60% at 273.15–523.15 K and 20–140 MPa only under the equilibrium condition, while flow is not considered.

Enhanced gas recovery by nitrogen injection: The effects of injection velocity during natural gas displacement in consolidated rocks

The choice of the flow velocity in EGR thus becomes important since higher injection rates could lead to premature mixing of the fluids and lower injection rates generally provide longer resident times for the fluids in contact and indirectly increases the mixing of the gases. Additionally, the medium peclet numbers mostly indicate the best injection rates that translate to a smoother displacement with a lower dispersion coefficient during the EGR process. Therefore, N2 Injection into natural gas reservoirs offers the potential to higher recovery efficiency with less mixing compared to conventional CO2 injection. The atmospheric air contained 79% of N2, making it readily available than CO2 with 400 ppm air composition. More so, N2 requires less compression ratio, which is why a lower amount of it was required to initiate much pressure in the CH4 reservoir during displacement. These made the use of N2 more economically feasible and friendly for the EGR process. A laboratory core flooding experiment was carried out to simulate the effect of injection velocity on CH4 recovery and dispersion coefficient. This was done at 40 °C, 1500 psig, and 0.2–1.0 ml/min injection rates. The results showed that a medium peclet number could be used to predict the best injection rate that translates to a smoother displacement with a lower dispersion coefficient during the EGR process. CH4 recovery and efficiency were highest at lower injection velocities experienced in both core samples. This could be attributed to insignificance nascent mixing observed as seen on their recorded low longitudinal dispersion coefficient results. Consequence, the experimental runs at high injection rates (0.6–1.0 ml/min) present a different scenario with lower recovery and efficiency due to their high interstitial velocities as the N2 plumes transverses into the core sample during CH4 displacement. Overall, the least methane production and efficiency were noticed in the Bandera core sample as a result of the heterogeneity effect due to the presence of higher clay contents in Bandera than Berea gray. When the capillary forces within the narrower pores in Bandera core sample were overcome, the clay particles occupied those pores thereby sealing some of the flow paths within the pore matrix. This reduces the flow channels, significantly, through which the injected N2 will flow to displace the residual CH4.

Influence of CH4 hydrate exploitation using depressurization and replacement methods on mechanical strength of hydrate-bearing sediment

This study analyzed the potential effects of gas hydrate (GH) exploitation on the geomechanical properties of hydrate-bearing sediment (HBS) by examining the combined effects of depressurization and CO2 injection using triaxial compression tests. The stress-strain behavior of the initial CH4 HBS showed strong hardening-softening characteristics and high peak strength, whereas milder hardening-softening behavior and reduced peak strength were observed after partial (20, 40, 60, and 80%) or complete GH dissociation (100%), indicating that the mechanical behavior clearly depended on dissociation ratios and GH saturations. In response to CO2 injection in partially dissociated HBS, subsequent CH4–CO2 hydrate exchange, and secondary CO2 hydrate formation, the mechanical strength of the replaced HBS recovered significantly, and stress-strain characteristics were similar to that of the 20% dissociated CH4 HBS. Although total CH4 recovery was increased by the combination of depressurization and replacement, optimum recovery was found at a dissociation ratio of 20% followed by replacement because production by replacement decreased as the dissociation ratio increased. These results contribute to the understanding of how depressurization and CO2 injection schemes may be combined to optimize energy recovery and CO2 sequestration. In particular, this research demonstrates that CH4–CO2 hydrate exchange and secondary GH formation are suitable methods for controlling and maintaining the mechanical stability of HBSs.

Replacement in CH4-CO2 hydrate below freezing point based on abnormal self-preservation differences of CH4 hydrate

CH4-CO2 replacement for natural gas hydrate exploitation is a win-win method to simultaneously realize CH4 recovery and CO2 sequestration. However, the exchange progress is severely blocked by the reformation of compact CO2 hydrate film. Constructing porous CO2 hydrate could be a promising approach to solve this annoyance. In consideration of the difference in ice layer defects and decomposition rate of CH4 hydrates at different temperatures in its anomalous self-preservation region, in this study, we proposed a concept of CH4-CO2 hydrate replacement by utilizing the multi-defective ice generated from dissociated CH4 hydrate to form porous CO2 hydrate. The CH4-CO2 hydrate exchange experiments occurred at 268.15 K and 272.15 K with rapid CH4 exhaust-CO2 injection were conducted. The results showed that the replacement efficiency at 272.15 K was much higher than at 268.15 K. In addition, we examined the replacement at 274.15 K and replacement with slow gas sweep at 268.15 K for comparison. These experimental results confirmed the possibility of the replacement concept.

Predictions on CH4 recovery factors using the CO2 replacement method to develop natural gas hydrate resources

Injecting CO2 into the hydrate reservoirs to replace CH4 is an effective method for the natural gas hydrate (NGH) exploitation and CO2 sequestration. The accurate prediction of the CH4 recovery factor under different pressures, temperatures, and CO2 injection amounts are essential for the design of the CO2 replacement process.However, conventional multiphase flash algorithms are not stable for CO2-containing hydrate system calculations because of inappropriate initial estimations on the hydrate phase fraction and composition. This paper proposed a new multiphase flash algorithm by developing a new initialization method for the hydrate phase fraction and composition as well as the solution procedure. A total of 61 sets of experimental data at pressures from 8 MPa and 16 MPa are applied to validate the new method. Results demonstrate that the new method successes in all the 61 cases, while the software PVTsim and CSMGem do not converge for 16 and 20 cases, respectively. Also, the average relative deviation between the calculated phase compositions and experimental values is less than 18 %, which represents a comparable accuracy to the above two software. Moreover, case studies are designed to research the variations of the CH4 recovery factor with the injected CO2 concentration in the hydrate reservoir. The most economical injected CO2 concentrations are discussed at specified reservoir conditions.

Alternating N2 gas injection as a potential technique for enhanced gas recovery and CO2 storage in consolidated rocks: an experimental study

The promotion of enhanced gas recovery (EGR) and CO2 storage is still shrouded in contention and is not well accepted, due to the excessive in situ CO2 mixing with the nascent natural gas. This adulterates the recovered CH4 and thus results in a high sweetening process cost thereby making the technique impractical. This has not only limited the field application of EGR in actual projects to a few trails but renders it uneconomical. This study aims to present, experimentally, alternating N2 injection as a potential technique for EGR and CO2 storage in sandstone rock cores. A laboratory core flooding experiment was carried out to simulate a detailed process of unsteady-state methane (CH4) displacement using Bandera grey core plug. This was carried out at 40 °C, 1500 psig, and 0.4 ml/min injection rate by alternative injection of N2 and CO2 in succession designed to suit the application based on optimum operating conditions. The results show that both CO2 storage capacity and CH4 recovery improved significantly when gas alternating gas (GAG) injection was considered. The best results were observed at lower N2 cushion volumes (1 and 2 PV). Therefore, the GAG injection method with N2 as cushion gas can potentially increase both CO2 storage and CH4 recovery of the gas reservoir. This technique if employed will assert the current position and provide vital information for further researches aimed at promoting environmental sustainability and economic viability of the EGR and CO2 sequestration processes.

Dynamic Fluid Interactions during CO2-Enhanced Coalbed Methane and CO2 Sequestration in Coal Seams. Part 1: CO2–CH4 Interactions

The injection of CO2 into coalbed methane (CBM) reservoirs to enhance methane recovery has a second desirable benefit in simultaneously sequestering CO2. However, the real-time dynamic evolution of native adsorbed and rejected non-adsorbed methane during the process of CO2-enhanced coalbed methane (CO2-ECBM) production remains poorly constrained as a result of the nonlinear and hysteretic response of both CO2–CH4 interactions (part 1) and CO2–H2O wettability (part 2) of the coal under recreated reservoir conditions. In part 1, we apply calibrated nuclear magnetic resonance (NMR) to explore mechanisms of methane desorption and CO2 replacement during multiple cycles of CO2-ECBM flooding under recreated in situ conditions. Results for contrasting sub-bituminous coal and anthracite indicate that the adsorbed methane sweep efficiency is improved by ∼16–26% with a single injection of CO2 over mere in situ desorption. Furthermore, CO2–CH4 displacement rates evolve during each CO2 injection cycle, first declining rapidly and then stabilizing with a long desorptive tail. Importantly, the cumulative methane sweep efficiency increases monotonically with successive cycles of CO2 injection, albeit at a reducing incremental efficiency, identifying the utility of cyclic CO2-ECBM as an effective method in both CO2 sequestration and enhanced gas recovery. Observed ratios of CO2 sorption capacities to CH4 recovery are 5.0 and 2.2 for sub-bituminous coal and anthracite, respectively, demonstrating an elevated potential for CO2 sequestration in sub-bituminous coals and more favorable CO2-ECBM recovery in anthracite, per unit mass of CO2 injected.

Novel wet-solid states serial anaerobic digestion process for enhancing methane recovery of aquatic plant biomass

Aquatic plant biomass is characterised by high moisture content and a lignocellulose structure. To apply the anaerobic digestion (AD) treatment to aquatic plants, the simultaneous achievement of high methane (CH4) recovery per biomass volume and high biodegradability have been a challenge owing to these characteristics. Herein, we propose a novel two-stage serial wet- and solid-state AD (SS-AD) system that quickly digests the labile cytoplasm fraction in the first wet AD reactor in a short retention time while slowly digesting the lignocellulosic fraction in the later SS-AD with long retention time. In this study, the effect of this serial AD on CH4 recovery and chemical oxygen demand (COD) balance from aquatic plant biomass was examined in a semi-continuous operation. Elodea nuttallii, which grows excessively in the southern basin of Lake Biwa, Japan, was used as the substrate. For comparison, single-stage AD with different hydraulic retention times (HRTs) (30 d and 15 d) was performed. The CH4 conversion efficiency in single-stage AD deteriorated from 47.6 to 33.1% COD with shortened HRT, probably owing to the low degradability of slowly degrading fraction (i.e. lignocellulose) in the short retention time. In contrast, the serial AD under the same HRT (15 d) as a single-stage AD exhibited higher CH4 conversion efficiency of 65.1% COD, mainly owing to the enhanced degradation of slowly degrading fraction because of the prolonged solid retention time (52.2 d) of the entire system. The CH4 recovery from the wet AD alone in the serial AD system surpassed that from the 30 d-HRT of the single-stage AD, possibly due to the appropriate HRT for labile fraction and/or the microbial recirculation. The serial wet and SS-AD was suggested as a suitable technology for the treatment of aquatic plant biomass with recalcitrant cell walls and a labile cytoplasm.

Mitigation of diffuse CH4 and H2S emissions from the liquid phase of UASB-based sewage treatment plants: challenges, techniques, and perspectives.

Upflow anaerobic sludge blanket (UASB) reactors are considered to be a sustainable and well-established technology for sewage treatment in warm climate countries. However, gases dissolved in the effluent of these reactors, CH4 and H2S in some instances, are a major drawback. These dissolved gases can be emitted into the atmosphere downstream of the anaerobic reactors, resulting in odour nuisance and, in the case of H2S, corrosion, while in the case of CH4, increasing greenhouse gas emissions with a significant loss of potentially recoverable energy. In this sense, this study aims to provide a critical review of the recent efforts to control CH4 and H2S dissolved in UASB reactor effluents, with a focus on the different available techniques. Different desorption techniques have been tested for the removal/recovery of dissolved CH4 and H2S: diffused aeration, simplified desorption chamber, packed desorption chamber, closed downflow hanging sponge reactor, membrane contactor, and vacuum desorption chamber. Other recent publications addressing the oxidation of these compounds in biological posttreatments with simultaneous nitrification/denitrification of ammonia were also discussed. Additionally, the rationale of CH4 recovery was determined by energy balance and carbon footprint approaches, and the H2S removal was examined by modelling its emission and atmospheric dispersion.