CO2 Hydrate Formation Research Articles

Kinetic and thermodynamic evaluation of effective combined promoters for CO2 hydrate formation

The increase in carbon dioxide (CO2) concentration in the atmosphere raises earth's temperature. CO2 emissions are closely related to human induced activities such as burning of fossil fuels and deforestation. So, to make the environment sustainable, carbon capture and storage (CCS) is required to reduce CO2 emissions. In this study, CO2 hydrate (CO2:6H2O) formation has been explored as an approach to capture CO2 in the integrated gasification combined cycle (IGCC) conditions. The formation of hydrate was experimentally investigated in an isochoric system with high-pressure volumetric analyzer (HPVA). The solubility of CO2 in water using experimental pressure–time (P-t) curves were analyzed to determine the formation of hydrate. Additionally, the effect of newly synthesized combined promoters and various driving forces were evaluated. The experimental results demonstrated that the CO2 uptake expanded as ΔP expanded and designated combined promoters type T1-5 and type T3-2 were the two best, acquiring a uptake of 5.95 and 5.57 mmol of CO2 per g of H2O separately. Ethylene glycol mono-ethyl ether (EGME) was demonstrated to be a good option to THF when linked with SDS, with a CO2 uptake of 5.45 mmol for the designated combined promoters T1A-2. Additionally, the total sum of CO2 devoured through hydrate development maximize as the measure of water inside mesoporous silica increased. All results of the studied parameters confirmed the reliability of experiments and successful implementation.

CO2 Hydrate Formation Promoted by a Bio-friendly Amino Acid L ‐ Isoleucine

We prove that L-isoleucine, a bio-friendly amino acid, can be used to greatly increased CO2 uptake kinetics in the formation of CO2 hydrate without stirring. As far as we know, L-Isoleucine is an accelerator that can effectively promotes the formation of CO2 hydrate (the gravimetric capacity achieved to 331 mg g−1 in 1000 min at a concentration of 0.2 wt%). We also provided a preliminary explanation for this promotion mechanism of L-isoleucine by comparing the structure-performance. Our results will provide a reference for exploring the promotion mechanism of CO2 hydrate.

Experimental study and modeling of the kinetics of carbon-dioxide hydrate formation and dissociation: A mass transfer limited kinetic approach

Kinetics of hydrate formation and dissociation of carbon dioxide studied through experiments carried out at isothermal-isobaric condition in a constant stirred tank reactor (CSTR). Experiments performed at different temperatures and pressure levels. Constant rates of CO2 mole consumption and mole production observed during hydrate formation and dissociation experiments. Accordingly, mass transfer limited hydrate kinetic models were used and mass transfer coefficients for CO2 hydrate formation and dissociation evaluated. It was found that mass transfer coefficients for CO2 hydrate dissociation are one order of magnitude larger than mass transfer coefficients for hydrate formation. The fact indicates that CO2 hydrate dissociation takes faster than formation. The evaluated mass transfer coefficient for CO2 hydrate formation and dissociation correlated as functions of temperature and pressure. The results can be applied for numerical modeling of underground storage of CO2 and simulation of hydrate based CO2 capture processes.

A study on the thermal-hydrodynamical-coupled CO2 flow process in the Ordos CCS-geological-formation

Non-isothermal flow in wellbores and geological formations is an important process associated with geologic storage of CO2. Technically, simulation of it is a highly challenging task as it often encounters phase transition problems for the fluids involved, which may greatly influence the profiles of pressure, temperature, and flowrate along the wellbore and consequently changes the injectivity of the relevant gas injection. In this paper we present a coupled non-isothermal wellbore/reservoir model for simulating the relevant flow behaviors, in which the non-isothermal wellbore flow model CO2Well and the reservoir simulator TOUGH2/ECO2N are combined to form a novel coupled flow model. The model developed is compared and verified by the existing wellbore-reservoir simulator T2Well with two CO2 injection examples. These examples demonstrate that the present method has considerable computational advantages in simulating wellbore flows when phase transition occurs. We then apply this model to the Ordos CCS demonstration project in China, and investigate the sophisticated, thermal-hydrodynamically-coupled flow processes observed there owning to injection of the condensed, cold CO2 that was directly captured from a nearby coal liquefaction plant. The results obtained by the simulation, along with the relevant field observations, provide in-depth insights into the CO2 flow behaviors in both the wellbore and the geological formation. For example, the simulation revealed that, in the wellbore, the heat exchange between the injected CO2 and the surrounding rock plays a critical role for the temperature distribution. It was also observed that phase transition occurred in the transferred period between the injection time and the shut-in time. In addition, both the simulation and field observation showed that most CO2 injected entered the topmost layer due to the high transmissivity of the rock. The simulation also showed that the temperature-change zone travelled slower than the CO2 plume. For example, the CO2 plume extended to 430 m away from the injection site after 31 months of CO2 injection, while the temperature-change zone extended merely about 90 m away, much smaller than that of the CO2 plume. The simulation suggests that the injectivity at this site is about 0.83 kg/(MPa·s). The simulation also suggests that the injection temperature should be relatively high (e.g., above −3 °C if the injection rate is more than 9.45 kg/s) to avoid formation of CO2 hydrate in the subsurface.

Numerical simulation of crystal growth of CO2 hydrate within microscopic Sand pores using phase field model for the estimation of effective permeability

Carbon dioxide capture and storage is an efficient technology to reduce CO2 emission. One of the reservoirs of CO2 is an aquifer in the sub-seabed geological formation under a caprock. However, there is a risk of CO2 leakage even though such probability is extremely low. When the water depth of a storage site is large: say, about 400 m or more, leaked CO2 changes its form to gas hydrate, which may block CO2 rise in the sediment. To estimate the sealing potential of CO2 hydrate, it is necessary to evaluate effective permeability of the sediment after CO2 hydrate forms. In this study, a series of numerical models were used to investigate microscopic hydrate distribution that essentially controls the effective permeability. The method consists of packing sand grains within microscopic computational domains, arranging water and CO2 phases in the pore space of the packed sand grains, placing multiple hydrate nuclei, and growing hydrate in the pores of the sand grains. First, we derived a value of the interface mobility of CO2 hydrate by fitting calculated growth rate of a hydrate spherule to a measurement in the literature. Then, CO2 hydrate formation was simulated within microscopic computational domains consisting of sand grains and water-CO2 two phases. Finally, efficient permeability was estimated using the results of the simulation of water flow through the pore space, regarding the formed hydrate as a solid. The calculation results indicated the differences in hydrate distribution in the pore space and in resulting effective permeability, depending on hydrate saturations, initial water saturations, and contact angles of water on the sand surface.

Hydrate Production Philosophy and Thermodynamic Calculations

The amount of energy in the form of natural gas hydrates is huge and likely substantially more than twice the amount of worldwide conventional fossil fuel. Various ways to produce these hydrates have been proposed over the latest five decades. Most of these hydrate production methods have been based on evaluation of hydrate stability limits rather than thermodynamic consideration and calculations. Typical examples are pressure reduction and thermal stimulation. In this work we discuss some of these proposed methods and use residual thermodynamics for all phases, including the hydrate phase, to evaluate free energy changes related to the changes in independent thermodynamic variables. Pressures, temperatures and composition of all relevant phases which participate in hydrate phase transitions are independent thermodynamic variables. Chemical potential and free energies are thermodynamic responses that determine whether the desired phase transitions are feasible or not. The associated heat needed is related to the first law of thermodynamics and enthalpies. It is argued that the pressure reduction method may not be feasible since the possible thermal gradients from the surroundings are basically low temperature heat that is unable to break water hydrogen bonds in the hydrate–water interface efficiently. Injecting carbon dioxide, on the other hand, leads to formation of new hydrate which generates excess heat compared to the enthalpy needed to dissociate the in situ CH4 hydrate. But the rapid formation of new CO2 hydrate that can block the pores, and also the low permeability of pure CO2 in aquifers, are motivations for adding N2. Optimum mole fractions of N2 based on thermodynamic considerations are discussed. On average, less than 30 mole% N2 can be efficient and feasible. Thermal stimulation using steam or hot water is not economically feasible. Adding massive amounts of methanol or other thermodynamic inhibitors is also technically efficient but far from economically feasible.

Experimental study on the characteristics of formation and dissociation of CO2 hydrates in porous media

Geologic carbon sequestration (GCS) has been pursued as a feasible strategy to store the large amount of CO2 to curb its emission to the atmosphere in an effort to mitigate the greenhouse effects. CO2 hydrate, which can form when the pressure and temperature satisfy its stability condition, can provide a self-trapping mechanism for an offshore CO2 geologic storage. For example, direct sequestration of CO2 in the form of hydrate crystals can be achieved in the storage aquifer under the seafloor. Besides, the formation of CO2 hydrates in an upper layer of the CO2 storage zone can potentially provide a secondary caprock. These applications, however, require a thorough understanding of the formation and dissociation of CO2 hydrates in porous media, which are largely unknown yet. In this manuscript, a laboratory study on the formation and dissociation of CO2 hydrates in two different environments, a two- (CO2-water) or three-phase (CO2-water in glass beads) condition, is presented. Based on the experimental results, it can be anticipated that the pressure and temperature change will be negligible when the formation of CO2 hydrate is induced for GCS in the actual soil/rock layers. Besides, the formation of CO2 hydrate in porous media may be faster, compared to the two-phase bulk condition that has been typically used in many laboratory studies, as solid grains help accelerate the hydrate formation by providing nucleus sites of crystals. Further elaborations on the role of solid grains would bring a clear path for the feasible application in the subsea area.

Influence of Low Dosage Green Extracts on CO2 Hydrate Formation

Gas clathrates or the gas hydrates are the solid ice particles encapsulating gas molecules (commonly methane - CH 4 and carbon dioxide - CO 2 ) within the water cavities, at moderately high-pressure and low-temperature conditions. The petroleum extraction process from the deep-sea environment favours the occurrence of hydrates, and CO 2 hydrates require milder p, T conditions than CH 4 hydrates. Thus, chocking the pipeline network and obstructing the petroleum flow; leading to a substantial economic loss and hazardous. Conventional hydrate inhibitors (methanol, ethanol, glycols, Amino acids, and ionic liquids, etc.) are used, which are chemically toxic, costly, and required in large volumes (30-50 wt %). Therefore a suitable additive preventing plug formation is on high demand. The present study disclosures the use of three green leaf extracts Azadirachta indica (Neem - NL), Piper betel (betel - BL), and Nelumbo nucifera (Indian lotus - LL) in low dosage (0.5 wt %) on the CO 2 hydrate formation. Experiments are conducted in the isochoric method, with 0.5 wt % green-additives. The hydrates nucleate at higher subcooling (̴ 7-9 K), and the conversion is about ̴ 33-40 %. The induction time is nearly the same both pure- H 2 O and H2O with LL, whereas, it is ̴3 and 4 times higher for NL and BL. The hydrate growth kinetics also indicate significant retardation (2 – 4 times). Thus, these bio-additives, in low-dosage, could be an effective THI and also KHI for preventing the CO 2 hydrates plugs.

Geological sequestration of CO2 in a water-bearing reservoir in hydrate-forming conditions

Higher concentration of carbon dioxide in the atmospheric air is a major environmental challenge and requires immediate attention for quicker mitigation. In that respect, the novel idea of CO2 sequestration in geological settings is worth examining from a quantitative perspective. In the present study, numerical simulation of CO2 injection into a porous reservoir is performed. The selected reservoir presents suitable thermodynamic conditions for CO2 hydrate formation. Unsteady simulations are carried out in one space dimension under isothermal and non-isothermal frameworks. An additional simulation of CO2 injection in a depleted methane hydrate reservoir is also reported. In the present study, the response of the reservoir to storage of CO2 is analyzed with respect to four parameters – reservoir porosity, initial water saturation and reservoir temperature and injection pressure. Quantities of interest are hydrate formation patterns and the cumulative CO2 mass sequestration in the reservoir as a function of time. Numerical experiments show that the initial water saturation is an important parameter as it affects both CO2 gas migration and hydrate formation. Isothermal simulation yields results that are similar to the non-isothermal model, thus suggesting that the isothermal assumption may be adopted for future CO2 injection studies. Hydrate formation rate of CO2 near the injection well is found to be one order of magnitude higher than the interior but its magnitude is quite small when compared to water and gas saturations. Higher injection pressure leads to a continuous increase in injected mass of CO2 primarily due to increased gas density, though an increase in hydrate formation near the injection well is also observed. Lower reservoir temperature supports a higher amount of hydrate formation from the injected mass of CO2 and is clearly desirable.

Geomechanical effects of carbon sequestration as CO2 hydrates and CO2-N2 hydrates on host submarine sediments

Over the past 10 years, more than 300 trillion kg of carbon dioxide (CO2) have been emitted into the atmosphere, deemed responsible for climate change. The capture and storage of CO2 has been therefore attracting research interests globally. CO2 injection in submarine sediments can provide a way of CO2 sequestration as solid hydrates in sediments by reacting with pore water. However, CO2 hydrate formation may occur relatively fast, resulting decreasing CO2 injectivity. In response, nitrogen (N2) addition has been suggested to prevent potential blockage through slower CO2-N2 hydrate formation process. Although there have been studies to explore this technique in methane hydrate recovery, little attention is paid to CO2 storage efficiency and geomechanical responses of host marine sediments. To better understand carbon sequestration efficiency via hydrate formation and related sediment geomechanical behaviour, this study presents numerical simulations for single well injection of pure CO2 and CO2-N2 mixture into submarine sediments. The results show that CO2-N2 mixture injection improves the efficiency of CO2 storage while maintaining relatively small deformation, which highlights the importance of injectivity and hydrate formation rate for CO2 storage as solid hydrates in submarine sediments.

Storing CO2as solid hydrate in shallow aquifers: Electrical resistivity measurements in hydrate-bearing sandstone

A recent proposed carbon dioxide (CO2) storage scheme suggests solid CO2hydrate formation at the base of the hydrate stability zone to facilitate safe, long-term storage of anthropogenic CO2. These high-density hydrate structures consist of individual CO2molecules confined in cages of hydrogen-bonded water molecules. Solid-state storage of CO2in shallow aquifers can improve the storage capacity greatly compared to supercritical CO2stored at greater depths. Moreover, impermeable hydrate layers directly above a liquid CO2plume will significantly retain unwanted migration of CO2toward the seabed. Thus, a structural trap accompanied by hydrate layers in a zone of favorable kinetics are likely to mitigate the overall risk of CO2leakage from the storage site. Geophysical monitoring of the CO2storage site includes electrical resistivity measurements that relies on empirical data to obtain saturation values. We have estimated the saturation exponent in Archie’s equation,n≈ 2.1 (harmonic mean) for CO2and brine saturated pore network, and for hydrate-bearing seal (SH < 0.4), during the process of storing liquid CO2in Bentheimer sandstone core samples. Our findings support efficient trapping of CO2by sedimentary hydrate formation and show a robust agreement between saturation values derived from PVT data and from modifying Archie’s equation.

A comparative study on the effects of Fe3O4 nanofluid, SDS and CTAB aqueous solutions on the CO2 hydrate formation

In this study, the effects of water-based Fe3O4 nanofluids containing 400 ppm sodium dodecyl sulfate (SDS) and 400 ppm cetyltrimethylammonium bromide (CTAB) in different concentrations of nanoparticles (0.05 wt%, 0.09 wt%, 0.15 wt%, 0.20 wt% and 0.25 wt%) on the kinetic parameters of carbon dioxide hydrate formation have been investigated and the results are compared with other aqueous solutions including pure water, aqueous solution of 400 ppm SDS, aqueous solution of 400 ppm CTAB and suspension of 0.15 wt% Fe3O4 nanoparticles. The kinetic parameters studied in this work included the mole of gas consumption, induction time and apparent rate constant. The experiments were performed at the initial pressure of 2.5 MPa and two temperatures of 274.15 K and 276.15 K. The experimental results showed that by increasing the concentration of nanoparticles up to 0.15% by weight, the effect of nanoparticles on the carbon dioxide hydrate formation increases. However, a further increase in nanoparticle concentration will reduce this effect. It was observed that the effect of the suspension of 0.15 wt% Fe3O4 nanoparticle on the carbon dioxide hydrate formation is more than the 400 ppm CTAB aqueous solution and less than the 400 ppm SDS aqueous solution. Results also showed that among different aqueous solutions, Fe3O4 nanofluid containing SDS with a concentration of 0.15 wt% nanoparticle is the best aqueous solution for carbon dioxide hydrate formation. In this nanofluid at 274.15 K, the induction time decreased by 70.6% and the mole of gas consumption and the apparent rate constant increased about 160% and 120.5%, respectively compared to pure water.

Modelling start-up injection of CO2 into highly-depleted gas fields

The development and verification of a homogeneous relaxation model for simulating the highly transient flow phenomena taking place during the start-up injection of CO2 into deep highly depleted gas fields is presented. The constituent mass, momentum, and energy conservation equations, incorporating a relaxation time to account for non-equilibrium effects, are solved numerically for single and two-phase flows along the steel lined injection well leading to the storage reservoir. Wall friction, gravitational field effects and heat transfer between the expanding fluid and the outer well layers are taken into account as source terms in the conservation equations. At the well inlet, the opening of the upstream flow regulator valve is modelled as an isenthalpic expansion process; whilst at the well outlet, a formation-specific pressure-mass flow rate correlation is adopted to characterise the storage site injectivity. The testing of the model is based on its application to CO2 injection into the depleted Golden Eye Reservoir in the North Sea for which the required design and operational data are publically available. Three injection scenarios involving a rapid, medium and slow linear ramping up of the injected CO2 flow rate to the peak nominal value of 33.5 kg/s are simulated. In each case, the predicted pressure and temperature transients at the top and bottom of the well are employed to ascertain the risks of well-bore thermal shocking, and interstitial ice or CO2 hydrate formation leading to its blockage due to the rapid expansion cooling of the CO2. The results demonstrate the efficacy of the proposed model as a tool for the development of optimal injection strategies and best-practice guidelines for the minimisation of the risks associated with the start-up injection of CO2 into depleted gas fields.

Effect of gas type and salinity on performance of produced water desalination using gas hydrates

Abstract In recent years, formation of gas hydrate has been considered as a suitable method for brine water desalination. In this study, for saline produced water treatment, design of experiment with two factors, the type of gas and electrical conductivity of initial brine solution (EC0) as a measure of salinity, were applied and removal efficiencies were analyzed. For this purpose, two different hydrate formers, CO2 and natural gas (NG) were separately mixed with different produced water samples. The hydrate formation reactions were carried out at 274.2 K in 35 and 95 bar, respectively, and removal efficiencies of produced water samples were tested. It has been found that with a three-stage hydrate process, 86% of dissolved minerals can be removed by the desalination process using CO2 hydrate formation gas while this amount will be 82% when NG is applied as hydrate former. Analysis of experiments indicated that the desalting efficiency depends on the hydrate-forming gas (CO2 > NG) as well as the amount of EC0 (high EC0 > low EC0).

Quantitative analysis of CO2 hydrate formation in porous media by proton NMR

AbstractGas hydrate is a nonstoichiometric crystal compound formed from water and gas. Most nonvisual studies on gas hydrate are unable to detect how much water is converted to hydrates, and thus, the hydrate stoichiometry calculations are inaccurate. This study investigated the CO2 hydrate formation process in porous media directly and quantitatively. The characteristics of the time‐variable consumption of hydrate formation indicated a two‐stage formation, hydrate enclathration and continuous occupancy. The enclathration stage occurred in the first 20 min of the formation when considerable heat is released. The continuous occupancy stage lasted longer than the hydrate enclathration because the empty cages in previously formed hydrates would also be occupied. The higher formation pressures can accelerate water consumption and increase cage occupancy. The compositions of completely formed CO2 hydrates at 2.7, 3.0, and 3.3 MPa and 275.15 K were determined as CO2·6.90H2O, CO2·6.70H2O, and CO2·6.49H2O, respectively.

CO2 removal from synthesized ternary gas mixtures used hydrate formation with sodium dodecyl sulfate(SDS) as additive

In order to investigate the hydrate formation kinetics of the ternary gas mixtures containing sodium dodecyl sulfate (SDS) and evaluate the applicability of hydrate based gas separation (HBGS) technology to biogas, synthesized ternary gas mixture (CH4/CO2N2) hydrate formation processes with different concentrations of SDS were investigated comprehensively in this work. The changes in the gas composition during the hydrate formation process, the gas consumption of the hydrate, the effective reaction time, the recovery factor of CH4, the split ratio of CO2, and the microscopic promotion mechanism of SDS for the hydrate were studied. The results indicated that the addition of SDS increased the hydrate reaction rate and gas consumption compared with those in a pure water system. The promotional effect of SDS improved with an increase in its concentration. The maximum CO2 split ratio was 0.95, at a driving force of 4.4 MPa and 0.05% SDS concentration. The maximum CH4 recovery factor was 3.18, at a driving force of 6.4 MPa and 0.03% SDS concentration. SDS promoted the formation of CO2 hydrate more strongly than that of CH4 and N2 for the ternary gas mixture. In summary, HBGS technology exhibited a good separation effect under two experimental conditions.

Study on CO2 Hydrate Formation Kinetics in Saline Water in the Presence of Low Concentrations of CH4.

Gas-hydrate formation has numerous potential applications in the fields of water desalination, capturing greenhouse gases, and energy storage. Hydrogen bonds between water and guest gas are essential for hydrates to form, and their presence in any system is greatly influenced by the presence of either electrolytes or inhibitors in the liquid or impurities in the gas phase. This study considers CH4 as a gaseous impurity in the gas stream employed to form hydrates. In developing gas-hydrate formation processes to serve multiple purposes, CO2 hydrate formation experiments were conducted in the presence of another hydrate-forming gas, CH4, at low concentrations in saline water. These experiments were conducted in both batch and stirred tank reactors in the presence of sodium dodecyl sulfate (SDS) as a kinetic additive at 3.5 MPa and 274.15 K, under isobaric and isothermal conditions. Gas loading was taken as the detection criterion for hydrate formation. It was observed that overall gas loading was hindered by more than 70% with the addition of salts after 2 days. The addition of CH4 to the gas stream led to a further reduction of approximately 30% of gas loading in the batch reactor under quiescent conditions. However, the addition of 100 ppm of SDS improved the gas loading by recovering 34% of the loss observed in volumetric gas loading through the addition of salts and CH4. The introduction of stirring improved the gas loading, and 64% of the loss was recovered through the addition of salts and CH4 after 34 h. The investigation was continued further by substituting CH4 with N2, whereupon accelerated hydrate formation was observed.

Evolving artificial intelligence techniques to model the hydrate-based desalination process of produced water

Abstract In this study, two artificial intelligence models based on an adaptive neuro-fuzzy inference system (ANFIS) and a support vector machine (SVM) technique have been successfully developed to predict the desalination efficiency of produced water through a hydrate-based desalination treatment process. A genetic algorithm as an evolutionary optimization method has been used to determine the optimal values of SVM model coefficients. To this end, compressed natural gas and CO2 hydrate formation experiments were carried out, and the desalination efficiency of produced water was measured and utilized for model training and validation. After model development, graphical and statistical analysis approaches have been applied to evaluate the performance of suggested models by a comparison of model predictions with measured experimental data. For the ANFIS model, the coefficient of determination (R2) and average absolute relative error (AARE) are 0.9927 and 0.58%, respectively. The values of AARE and R2 for the SVM model are obtained 0.35% and 0.9985, respectively. These statistical criteria confirm excellent accuracy and robustness of intelligent models in predicting the desalination efficiency of produced water through the hydrate-based desalination treatment process. Furthermore, the Leverage statistical technique has been carried out to define the outliers. The obtained results demonstrate that all experimental data are reliable and both ANFIS and SVM models are statistically valid.

Experimental Simulation of the Self-Trapping Mechanism for CO2 Sequestration into Marine Sediments

CO2 hydrates are ice-like solid lattice compounds composed of hydrogen-bonded cages of water molecules that encapsulate guest CO2 molecules. The formation of CO2 hydrates in unconsolidated sediments significantly decreases their permeability and increases their stiffness. CO2 hydrate-bearing sediments can, therefore, act as cap-rocks and prevent CO2 leakage from a CO2-stored layer. In this study, we conducted an experimental simulation of CO2 geological storage into marine unconsolidated sediments. CO2 hydrates formed during the CO2 liquid injection process and prevented any upward flow of CO2. Temperature, pressure, P-wave velocity, and electrical resistance were measured during the experiment, and their measurement results verified the occurrence of the self-trapping effect induced by CO2 hydrate formation. Several analyses using the experimental results revealed that CO2 hydrate bearing-sediments have a considerable sealing capacity. Minimum breakthrough pressure and maximum absolute permeability are estimated to be 0.71 MPa and 5.55 × 10−4 darcys, respectively.

Stages in the Dynamics of Hydrate Formation and Consequences for Design of Experiments for Hydrate Formation in Sediments

Natural gas hydrates in sediments can never reach thermodynamic equilibrium. Every section of any hydrate-filled reservoir is unique and resides in a stationary balance that depends on many factors. Fluxes of hydrocarbons from below support formation of new hydrate, and inflow of water through fracture systems leads to hydrate dissociation. Mineral/fluid/hydrate interaction and geochemistry are some of the many other factors that determine local hydrate saturation in the pores. Even when using real sediments from coring it is impossible to reproduce in the laboratory a natural gas hydrate reservoir which has developed over geological time-scales. In this work we discuss the various stages of hydrate formation, with a focus on dynamic rate limiting processes which can lead to trapped pockets of gas and trapped liquid water inside hydrate. Heterogeneous hydrate nucleation on the interface between liquid water and the phase containing the hydrate former rapidly leads to mass transport limiting films of hydrate. These hydrate films can delay the onset of massive, and visible, hydrate growth by several hours. Heat transport in systems of liquid water and hydrate is orders of magnitude faster than mass transport. We demonstrate that a simple mass transport model is able to predict induction times for selective available experimental data for CO2 hydrate formation and CH4 hydrate formation. Another route to hydrate nucleation is towards mineral surfaces. CH4 cannot adsorb directly but can get trapped in water structures as a secondary adsorption. H2S has a significant dipole moment and can adsorb directly on mineral surfaces. The quadropole-moment in CO2 also plays a significant role in adsorption on minerals. Hydrate that nucleates toward minerals cannot stick to the mineral surfaces so the role of these nucleation sites is to produce hydrate cores for further growth elsewhere in the system. Various ways to overcome these obstacles and create realistic hydrate saturation in laboratory sediment are also discussed.