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Sol-gel Synthesis and Characterization of Gels with Compositions Relevant to Hydrated Glass Alteration Layers
During the processes associated with glass corrosion, porous alteration gel layers typically form upon exposure to aqueous conditions for extended time periods. The impacts of the alteration gel layer on glass durability have not been agreed upon in the glass science community. In particular, the formation mechanisms of the alteration gel layers are still largely unknown and require further investigation. However, alteration gel layers often require months to years to develop and are often too thin to adequately characterize. Meanwhile, silicate sol-gels are relatively easy to synthesize in bulk with custom compositions relevant to alteration gel layers. If glass alteration gel layers and synthetic sol-gel silicate gels demonstrate physical and chemical properties that are sufficiently similar, synthetic silicate gels could be used as analogues for glass alteration gel layers in future studies. In this study, sol-gels were made with custom compositions at various pH values to evaluate the effect of pH on gel structure and morphology. Several other variables were examined as well, such as composition, drying, and aging. Sol-gels were created by sequential additions of organometallic precursors in a single container. Synthesis procedural steps are provided in further detail within the text. Sol-gels were analyzed with several techniques including Small Angle X-ray Scattering (SAXS), gas adsorption, and He pynchometry to determine the effects of the variables on physical properties. Results show that sol-gels prepared at pH 3 consistently contained fewer primary particles with diameters larger than 72 Å and fewer pores with diameters larger than 300 Å compared to sol-gels synthesized at pH 7 and 9. Composition was shown to have no discernable effect on primary particle and pore sizes at any pH.
Pore-scale evidence of ion exclusion during methane hydrate growth and evolution of hydrate pore-habit in sandy sediments
Hydrate-bearing sediments constitute complex hydrological systems, within which the pore habit of hydrate significantly affects all physical properties. However, there is scarce pore-scale evidence of the evolution of hydrate growth in porous media and the influence of water salinity in the micro-morphology of hydrate. In this paper, we used X-ray computed micro-tomography (CT) to monitor three experiments of methane hydrate growth in sand partially saturated with either NaBr or KI brine under excess-gas conditions. Gas, brine and hydrate are observed to co-exist at the pore-scale during the evolution of hydrate pore-habit towards three-phase equilibrium. The experiments and data analysis reveal that (1) hydrate forms as a porous medium mixed with inclusions of brine and gas, where hydrate and brine evolve gradually into separate phases as hydrate cages exclude salt ions, (2) hydrate growth mobilizes water over fairly long distances resulting in heterogeneous hydrate distribution, and (3) hydrate can exhibit interconnecting pore-habit at local hydrate saturations higher than ~50%, even if grown under excess-gas conditions. The results imply that hydrate micro-morphology and pore habit evolve during hydrate formation and, we suggest, so do the physical properties of hydrate-bearing sediments. Furthermore, our findings provide new insights into the micro-morphology of hydrate and evolution of the properties of hydrate-bearing sediments synthesized in the laboratory and in natural systems.
Dynamics of Gas Flow and Hydrate Formation within the Hydrate Stability Zone
Methane hydrate comprises a significant piece of the global carbon cycle and is an important potential energy resource. Thick marine sands around the world contain free gas beneath and high concentrations of methane hydrate far above the base of the hydrate stability zone. The mechanisms controlling gas transport and hydrate formation within the region where hydrate is stable remains an important research question. I developed a new experimental method to investigate the fundamental behaviors associated with hydrate formation during gas flow into the hydrate stability zone. First, I performed a set of experiments at the same experimental conditions, to determine the repeatability of this behavior. I compared these results to those from an experiment performed outside the hydrate stability zone to elucidate the change in intrinsic gas flow behavior due to hydrate formation. Second, I performed additional experiments at a range of flow rates as well as several shut-in experiments, where I observed long-term hydrate formation after flow took place. I analyzed the bulk and core-scale behaviors of these experiments using a combination of mass balance and computed-tomography analyses. I found that many of my experimentally observed behaviors are not accurately described by previous models and that the mechanism for gas transport was fundamentally different than typically assumed. I proposed that hydrate formation at the gas-brine interface separates the gas and brine phases and limits hydrate formation to methane transport through the hydrate. This behavior produced temporary flow blockages that were mitigated when the hydrate skin fails due to pressure gradients across the sample. This behavior also produced different thermodynamics states on either side of the hydrate that could persist for hundreds to thousands of years. These results provide an alternative mechanism for gas transport and hydrate formation through the hydrate stability zone that does not require the gas, hydrate, and brine to be at three-phase equilibrium. This mechanism provides a first-order connection between experimentally observed micro-scale phenomena and field-scale gas transport and hydrate formation behaviors in these reservoirs.
Characterization of the Structural–Stratigraphic and Reservoir Controls on the Occurrence of Gas Hydrates in the Eileen Gas Hydrate Trend, Alaska North Slope
One of the most studied permafrost-associated gas hydrate accumulations in Arctic Alaska is the Eileen Gas Hydrate Trend. This study provides a detailed re-examination of the Eileen Gas Hydrate Trend with a focus on the gas hydrate accumulation in the western part of the Prudhoe Bay Unit. This integrated analysis of downhole well log data and published geophysical data has provided new insight on structural, stratigraphic, and reservoir controls on the occurrence of gas hydrates in the Eileen Gas Hydrate Trend. This study revealed the relatively complex nature of the gas hydrate occurrences in the Eileen Gas Hydrate Trend, with gas hydrates present in a series of coarsening upward, laterally pervasive, mostly fine-grained sand beds exhibiting high gas hydrate saturations. Most of the gas hydrate-bearing reservoirs in the Eileen Gas Hydrate Trend are laterally segmented into distinct northwest- to southeast-trending fault blocks, occur in a combination of structural–stratigraphic traps, and are only partially hydrate filled with distinct down-dip water contacts. These findings suggest that the traditional parts of a petroleum system (i.e., reservoir, gas source, gas migration, and geologic timing of the system formation) also control the occurrence of gas hydrates in the Eileen Gas Hydrate Trend.
Optimal Pre-hydration Age for CO 2 Sequestration through Portland Cement Carbonation
An emerging technology of CO 2 sequestration in Portland cement (PC) is through accelerated carbonation, where PC is intentionally carbonated at early hydration age and reinitiates long-term hydration upon completion of carbonation. However, the current literature has overlooked a fact that different PC hydration ages prior to carbonation (pre-hydration) could lead to distinct carbonation efficiencies and subsequent hydration behaviors (post-hydration). Here, we examine the effects of length of pre-hydration period on CO 2 uptake and on the hydration extent and final strength at 28 days. The CO 2 and H 2 O profiles in the carbonated PC were examined with thermogravimetric analysis/derivative thermogravimetric analysis. The pre-hydration path was traced with isothermal calorimetry. Experimental results suggested that extension of pre-hydration decreased CO 2 uptake, but enhanced the extent of PC hydration at 28 days. It was found that a pre-hydration beyond the late deceleration period of PC hydration (where heat generation is slowing down) led to a higher hydrate content of cement paste, hence forming a higher compressive strength of mortar compared to the noncarbonated benchmarks at 28 days. The lesser carbonation-induced water loss and the nucleation seeding enabled by calcium carbonate are likely responsible for this effect. Furthermore, the finding reported here should be useful for fine tuning PC carbonation process for CO 2 sequestration in concrete.
Gas Hydrate Saturation Estimation Form Acoustic Log Data in the 2018 Alaska North Slope Hydrate-01 Stratigraphic Test
Completed in December 2018, the Alaska North Slope Hydrate 01 stratigraphic test well provides a wealth of logging-while-drilling (LWD) data for strata to below the base of gas hydrate stability (BGHS). This well is intended to be the first of three wells drilled for a comprehensive long-term gas hydrate production test conducted by the National Energy Technology Laboratory, the Japan Oil, Gas and Metals National Corporation, and the U.S. Geological Survey (USGS). The Hydrate 01 stratigraphic test well confirmed the presence of gas hydrate in two sand reservoirs within the hydrate stability zone, indicating the suitability of this location for a long-term gas hydrate production test.<p>The USGS, using an effective-medium-theory rock-physics approach, has estimated gas hydrate saturations from compressional (P) and shear (S) wave log data acquired in the Hydrate 01 well. We assume that gas hydrate occurs as pore-filling load-bearing material (i.e., part of the grain matrix). For Unit D, approximately 500 feet above the BGHS, both P-wave and S-wave acoustic logs indicate moderate gas hydrate saturations with S-wave results slightly lower than those for P-waves. For the Unit B, located just above the BGHS, we obtain moderate to high gas hydrate saturation estimates from both sonic logs. Our P-wave saturation estimates agree well with results from electrical-resistivity-based estimates, whereas estimates from nuclear magnetic resonance LWD data generally suggest 5 to 10 percent higher saturations; our S-wave results suggest lower saturations. These differences likely indicate complexities in the form of gas hydrate occurrence within the sediment pore space, potentially including differences between hydrate occurrence in Units D and B.</p>
DOE NETL Gas Hydrate Project FWP 65213: Kinetic Parameters for the Exchange of Hydrate Formers (Final Report)
This report documents the research activities sponsored by the U.S. Department of Energy, National Energy Technology Laboratory (NETL), by the Pacific Northwest National Laboratory (PNNL) for the gas hydrate project entitled, “Kinetic Parameters for the Exchange of Hydrate Formers.” This project started June 1, 2013 and concluded December 31, 2018, and comprised five budget periods, under FWP-65213. The overarching goal of this project was to gain an improved understanding of the dynamic processes of gas hydrate accumulations in geologic media by combining laboratory studies, numerical simulation, and analysis of shipboard infrared imaging of hydrate core samples. This project comprised four principal components: 1) fundamental laboratory investigations, 2) numerical simulator development and verification, 3) hydrate core characterization and analysis, and 4) applied laboratory and numerical investigations. Laboratory and field experiments have demonstrated the four core methodologies for producing natural gas hydrates from geologic formations: 1) depressurization, 2) thermal stimulation, 3) inhibitor injection, and 4) guest molecule exchange. Converting these methodologies into viable commercial technologies remains challenging, either from an economic or technical perspective. This project was largely focused with the technical challenges associated with the guest molecule exchange method, which is often referred to as gas swapping. Previous research by PNNL had shown that gas swapping with pure CO 2 was not feasible, as first originally thought, principally due to the formation of secondary hydrates, which clogged or reduced the effective permeability of the hydrate-bearing formation. This research was directed at discovering the potential for using mixtures of gases to affect the gas swapping methodology at commercial scales. The Ignik Sikumi Gas Hydrate Field Trial demonstrated the injection of a N 2 -CO 2 gas mixture into a natural gas hydrate bearing layer, and exchange behavior with the CH 4 hydrate former or guest molecules. The original concept behind the use of a N 2 -CO 2 was to maintain gas conditions at the reservoir state. Pure CO 2 would have existed under supercritical conditions, with an associated density closer to a liquid than gas. One of the key outcomes from this research project has been the discovery, through laboratory experiments and numerical simulation, that gas mixtures, especially those with components having different gas hydrate equilibria conditions provide a control option for the guest molecule exchange methodology. For example, the dissociation or formation of hydrate could be controlled by adjusting the composition of the gas mixture. This research project was dynamic in that the discoveries during each budget period would set the course of research during successive budget periods. Therefore, this report is arranged in chronological order progressing through the five budget periods of the project.
Xenon Hydrate as an Analog of Methane Hydrate in Geologic Systems Out of Thermodynamic Equilibrium
Methane hydrate occurs naturally under pressure and temperature conditions that are not straightforward to replicate experimentally. Xenon has emerged as an attractive laboratory alternative to methane for studying hydrate formation and dissociation in multiphase systems, given that it forms hydrates under milder conditions. However, building reliable analogies between the two hydrates requires systematic comparisons, which are currently lacking. We address this gap by developing a theoretical and computational model of gas hydrates under equilibrium and nonequilibrium conditions. We first compare equilibrium phase behaviors of the Xe·H 2 O and CH 4 ·H 2 O systems by calculating their isobaric phase diagram, and then study the nonequilibrium kinetics of interfacial hydrate growth using a phase field model. Our results show that Xe·H 2 O is a good experimental analog to CH 4 ·H 2 O, but there are key differences to consider. In particular, the aqueous solubility of xenon is altered by the presence of hydrate, similar to what is observed for methane; but xenon is consistently less soluble than methane. Xenon hydrate has a wider nonstoichiometry region, which could lead to a thicker hydrate layer at the gas-liquid interface when grown under similar kinetic forcing conditions. For both systems, our numerical calculations reveal that hydrate nonstoichiometry coupled with hydrate formation dynamics leads to a compositional gradient across the hydrate layer, where the stoichiometric ratio increases from the gas-facing side to the liquid-facing side. Our analysis suggests that accurate composition measurements could be used to infer the kinetic history of hydrate formation in natural settings where gas is abundant.
Effect of Gas Flow Rate on Hydrate Formation Within the Hydrate Stability Zone
We form methane hydrate in brine-saturated, coarse-grained samples, under hydrate-stable conditions, by injecting methane vapor at various flow rates. Decreasing the flow rate results in higher hydrate saturation, lower brine saturation, a smaller affected volume, and larger average pressure differentials across the sample. We interpret that the longer execution times at lower flow rates allow for additional methane transport and hydrate formation at the hydrate-brine interface. As a result, the hydrate skin is thicker at lower flow rates and thus is capable of sustaining larger pressure differentials. In several experiments, we stop brine flow and supply methane gas to the sample for an additional 800 hrs. During this period, hydrate continues to form, pressure differentials develop, and the bulk density changes within the affected volume. We interpret that there is gas present in the sample that is disconnected from the gas source. Hydrate forms around the disconnected gas due to methane transport through the skin that surrounds it, causing the internal gas pressure to decline and leading to inward collapse and net volume decrease. This lowers the brine pressure and creates a differential pressure across the sample that induces gas flow. This study indicates that lower gas flow rates through the hydrate stability zone can produce very high saturations of hydrate but require a larger differential pressure to sustain flow. Ultimately, this process is an alternative mechanism for sustained upward gas flow and hydrate formation far above the base of the hydrate stability zone.
Interactions of clathrate hydrate promoters sodium dodecyl sulfate and tetrahydrofuran investigated using 1H diffusion nuclear magnetic resonance at hydrate-forming conditions
Thermodynamic hydrate promoters and kinetic hydrate promoters can be used to reduce the P–T conditions for clathrate hydrate synthesis to decrease the nucleation induction time while increasing growth rates. Two commonly used promoters for hydrate research are tetrahydrofuran (THF) and sodium dodecyl sulfate (SDS), which can increase the overall hydrate promotion when used in tandem as compared to individually. There are several molecular theories regarding how SDS promotes hydrate growth. This study explores the micellular theory, for which hydrate formation depends on surfactant aggregates (micelles) at a critical micelle concentration (CMC) to increase the interfacial surface area. The micellular theory is the most investigated and criticized surfactant hydrate promotion theory. To address questions related to micellar behavior, this study investigates the intermolecular behavior between SDS and THF for the identification of micelles at hydrate-forming conditions. The systems explored contained THF at 3 and 5 wt. % with varying concentrations of SDS below and above the CMC. Several methods including a qualitative visual method, conductivity, interfacial tensiometry, 13C Liquid-state Nuclear Magnetic Resonance (NMR) spectroscopy, and 1H diffusion NMR spectroscopy were evaluated at temperatures below the Krafft point of SDS and above 0 °C. The presence of THF at low concentrations decreased the critical temperature for the formation of SDS micelles, where SDS is solubilized in THF/water solution at hydrate-forming temperatures without precipitation. The CMC of SDS was decreased significantly even at hydrate-forming conditions. Mixed surfactant–cosolvent micellular behavior of SDS in the presence of low concentrations of THF was confirmed at hydrate-forming conditions above 0 °C.
Petrophysical and geomechanical properties of gas hydrate-bearing sediments recovered from Alaska North Slope 2018 Hydrate-01 Stratigraphic Test Well
Knowledge of petrophysical and geomechanical properties of gas hydrate-bearing sediments are essential for predicting reservoir response due to gas production from gas hydrate reservoirs. That information will be critical parameters for designing production well completion such as specification of depressurization pump, water storage tank, and mesh size of sand screen. In December 2018, Stratigraphic Test Well Hydrate-01 was drilled in the western part of the Prudhoe Bay Unit, Alaska North Slope as part of the technical planning effort for a future long-term production test by collaborative team of DOE/NETL, USGS, and MH21-S (Boswell et al., 2020, Collett et al., 2020, Okinaka et al., 2020). Data set of logging-while-drilling (LWD) were acquired (Haines et al., 2020, Suzuki et al., 2019) and core sampling depth was determined on-site.Side-wall pressure coring was conducted to recover gas hydrate-bearing sediments from two reservoir sections named Unit-B and Unit-D. A total of 34 cores were successfully recovered by 5 runs of a wire-line deployed pressure corer (CoreVault® System - Halliburton). Core analysis scheme of this project are shown in Figure 1. All cores were quenched in liquid nitrogen while at high pressure in the laboratory of Stratum Reservoir, LLC. at Anchorage (Figure 1, a)). And the cores were removed from the pressure corer autoclave with temperature support of dry ice and stored under liquid nitrogen at atmospheric pressure. 19 damaged cores were processed to index property measurements directly such as grain size, grain density. 4 of another 17 cores were depressurized and trimmed for making a plug to analyze petrophysical properties of host sediments. Unsteady-state permeability test was conducted to obtain relative water permeability to gas and core scale NMR T2 distribution measurement was performed for evaluating pore size distribution at Houston (Figure 1, b)). Remained high quality 13 cores were preserved with gas hydrate for advanced laboratory analysis. National Institute of Advanced Industrial Science and Technology, as a part of the Japanese National Hydrate Research Program (MH21-S, funded by Ministry of Economy, Trade and Industry), received the samples at Sapporo, Japan for advanced core analysis. High-resolution X-ray CT was used to analyze the quality of the samples, which showed undisturbed lithological layers. Cores were lathed into cylindrical shape and distributed for multi property measurements (Figure 1, c)).<p>As a result, sediment from Unit-D is categorized as silty sand at ~37% porosity with ~80% gas hydrate saturation. An average hydration number n = 6.16 was measured by Raman spectroscopy. An average intrinsic permeability of ~400 mD and in situ effective permeability (with hydrate) on the order of ~10 mD. The Unit B recovered cores consisted of well sorted sand at ~40% porosity with ~95% gas hydrate saturation. An average intrinsic permeability of ~1 Darcy and in situ effective permeability on the order of ~30 mD was measured for the Unit B cores. There was a small permeability reduction due to porosity loss with increasing effective stress that simulated consolidation behavior along with depressurization in the highly permeable sandy sediment. The apparent minimum change in porosity and permeability may be caused by the low compressibility of quartz sand grains in the recovered cores. XRD and thermal conductivity analysis also suggested high quartz content. Triaxial compression tests established internal friction angles based on the Mohr-Coulomb's failure criterion, which are 40° for hydrate-bearing sediment and 29.8° for hydrate free sediment.</p>
An experimental study on gas-liquid phase fluid migration in hydrate-bearing sediments during hydrate dissociation
Natural gas hydrate production tests face problems such as severe sand blockage, poor gas-liquid phase separation, and significant land subsidence. This is because of the insufficient understanding of the complex phase transition and gas-liquid multi-phase fluid migration during hydrate dissociation. In hydrate-bearing sediment systems, hydrate phase transition couples with gas-liquid fluid migration. The phase transition causes changes in pore structure, which in turn modifies porous infiltration parameters and fluid flow capacity. Meanwhile, alterations in phase interfaces affect key parameters like surface tension and wettability. Gas-liquid fluid migration influences heat and mass transfer, thus affecting phase equilibrium and dissociation rates. To bridge the gap in describing gas-liquid fluid migration during hydrate dissociation in experiments, this research innovatively integrated an unsteady-state gas displacement by water and a quantitative hydrate dissociation process, independently developed a multi-phase seepage experimental system suitable for hydrate dissociation and determined the relationship between seepage parameters and hydrate saturation under different porosity. The results are as follows: a) Core samples with higher initial porosity show a greater recovery rate of fluid flow capacity. b) The retarding effect of multi-phase fluid has a more significant impact on the migration of the wetting phase fluid (water) than that of the non-wetting phase fluid (methane). c) During hydrate dissociation, the evolution of absolute permeability shows an “S-shaped” pattern, and the evolution of relative permeability shows a “wiring-harness” pattern. In conclusion, the findings can provide a theoretical basis for preventing geological disasters and for geotechnical engineering design during hydrate production.
Experimental Investigation of Gas Flow and Hydrate Formation Within the Hydrate Stability Zone
Here, we form methane hydrate by injecting methane gas into a brine-saturated, coarse-grained sample under hydrate-stable thermodynamic conditions. Hydrate forms to a saturation of 11%, which is much lower than that predicted assuming three-phase (gas-hydrate-brine) thermodynamic equilibrium (67%). During hydrate formation, there are temporary flow blockages. We interpret that a hydrate skin forms a physical barrier at the gas-brine interface. The skin fails periodically when the pressure differential exceeds the skin strength. Once the skin is present, further hydrate formation is limited by the rate that methane can diffuse through the solid skin. This process produces distinct thermodynamic states on either side of the skin that allows gas to flow through the sample. This study illuminates how gas can be transported through the hydrate stability zone and thus provides a mechanism for the formation of concentrated hydrate deposits in sand reservoirs. It also illustrates that models that assume local equilibrium at the core-scale and larger may not capture the fundamental behaviors of these gas flow and hydrate formation processes.
Impact of hydrate saturation on water permeability in hydrate-bearing sediments
Permeability of the hydrate-bearing sediments vitally affects the hydrate dissociation process as well as the rate and efficiency of gas production. Reported permeability values are observed to be widely are very scattered owing to the dependence on multiple factors such as experimental conditions and test procedures. It is critical that the permeability is measured accurately to enable prediction of long-term gas production using numerical simulation for an economic development of hydrate-bearing reservoirs. In this study, the tetrahydrofuran (THF) hydrates that exhibit pore habits of the pore-filling pattern are formed in sediments, and the water permeability is quantified as a function of hydrate saturation. The results reveal that a decrease in the permeability for an increase in the hydrate saturation. Based on the measured values that are bounded by Kozeny grain-coating and pore-filling models, the fitting parameters of the empirical permeability models are indicated for use in numerical simulation of long-term hydrate dissociation. Wave velocity measurements reveal pore habits of pore-filling pattern of THF hydrates in the sediments with S h < 0.5, and a gradual transition to patchy and load-bearing pore-habits when S h > 0.6. The numerical simulation results obtained using the complementary pore-network model suggest that the THF hydrates in the sediments may form in small clusters with an average patch size of ~4 pores.
Electrical Properties of Carbon Dioxide Hydrate: Implications for Monitoring CO 2 in the Gas Hydrate Stability Zone
CO 2 and CH 4 clathrate hydrates are of keen interest for energy and carbon cycle considerations. While both typically form on Earth as cubic structure I (sI), we find that pure CO 2 hydrate exhibits over an order of magnitude higher electrical conductivity ( σ ) than pure CH 4 hydrate at geologically relevant temperatures. In this study, the conductivity was obtained from frequency-dependent impedance ( Z ) measurements made on polycrystalline CO 2 hydrate (CO 2 ·6.0 ± 0.2H 2 O by methods here) with 25% gas-filled porosity, compared with CH 4 hydrate (CH 4 ·5.9H 2 O) formed and measured in the same apparatus and exhibiting closely matching grain characteristics. The conductivity of CO 2 hydrate is 6.5 × 10 –4 S/m at 273K with an activation energy ( E a ) of 46.5 kJ/mol at 260–281 K, compared with ~5 × 10 –5 S/m and 34.8 kJ/m for CH 4 hydrate. Equivalent circuit modeling indicates that different pathways govern conduction in CO 2 versus CH 4 hydrate. Results show promise for use of electromagnetic methods in monitoring CO 2 hydrate formation in certain natural settings or in CO 2 /CH 4 exchange efforts.
India National Gas Hydrate Program Expedition 02 Summary of Scientific Results: Numerical Simulation of Reservoir Response to Depressurization
The India National Gas Hydrate Program Expedition 02 (NGHP-02) discovered gas hydrate at high saturation in sand reservoirs at several sites in the deepwater Bay of Bengal. To assess the potential response of those deposits to scientific depressurization experiments, comprehensive geologic models were constructed to enable numerical simulation for two sites. Both sites (NGHP-02-09 and NGHP-02-16) feature thick sequences of thinly-interbedded reservoir and non-reservoir facies at sub-seafloor depths less than 300m and sub-sea depths of 2400m or more. These settings pose significant challenges to current modeling capabilities. First, the thinly-interbedded reservoir architecture complicates the determination of basic reservoir parameters from both log and core data due to measurement resolution issues. Secondly, the fine scale variation in sediment properties imparts great contrasts in key parameters over very short distances, creating high gradients at multiple scales and varying orientations that necessitate careful design of high-definition simulation grids. Thirdly, the deposits include internal sources of water, as well as a range of complex boundary conditions, including variable permeability within the overlying mud-rich “seals,” that complicate reservoir depressurization. Lastly, because of the unique combination of great water depth and relatively shallow sub-seafloor depth: models designed to maximize the dissociation rate impose large pressure drawdowns on relatively low-strength sediments. This condition renders the proper evaluation and integration of the geomechanical response to hydrate dissociation critical. In this report, we review the history of gas hydrate reservoir simulation, discuss methods for creating geologic input models, and summarize the key findings and implications of the collaborative NGHP-02 numerical simulation effort. Together, the studies confirm the viability of the modeled accumulations for scientific testing and identify key challenges related to the selection of specific test sites and the design of test wells.