Mapping Gas Hydrate Dynamics in Porous Media : Experimental Studies of Gas Hydrates as a Source of CH4 and Sink for CO2

The world needs more energy and the energy has to be more sustainable with respect to carbon dioxide (CO2) emissions. This is the backdrop for studying the diverse applications of gas hydrates in nature. The ice-like substance is found worldwide as inclusions in the pore space of subsurface sediments and may affect the global energy supply and climate profoundly: 1) The large amounts of hydrate-bound natural gas, predominantly methane gas (CH4), could provide the world with energy for decades. Global consumption of natural gas is expected to increase with 45% by 2030 (IEA, 2018b). Countries like Japan, China, India and South Korea are seeking to increase their energy security by developing natural gas production from subsurface accumulations of gas hydrates. 2) The natural affinity for CO2 to form gas hydrates in the shallow subsurface could increase the storage capacity and security of carbon sequestration. Carbon capture and storage (CCS) is the removal of CO2 from the atmosphere (or before it reaches the atmosphere) and subsequent long-term storage of the CO2 in the subsurface. The projections of the IPCC that seeks to limit global warming to 1.5°C above the pre-industrial level rely on the use of CO2 removal from the atmosphere on the order of 100 – 1000 gigatonnes of CO2 (GtCO2) during this century (IPCC, 2018). The formation of CO2 hydrates could provide a self-sealing mechanism during CO2 storage in saline aquifers which would decrease the risk of CO2 leakage considerably. In both cases, fundamental knowledge about gas hydrates in porous media is needed. The scientific work presented in this thesis contributes to the understanding of CH4 and CO2 hydrates in sediments with special emphasis on phase transitions and fluid flow in hydrate-saturated porous rock. Coupling the fluid flow with gas hydrate saturation and growth pattern is important to control the production rate of CH4 gas from CH4 gas hydrates and to model the sealing capacity of CO2 gas hydrates. The rate and distribution of fluid flow during gas hydrate phase transitions in sediments were studied using a multiscale approach. Permeability measurements and quantitative mapping of water saturation were conducted on cylindrical Bentheim sandstone core plugs by high-precision pressure-volume-temperature (PVT) recordings and magnetic resonance imaging (MRI). Pore-scale mapping of gas hydrate phase transitions was facilitated by etched silicon micromodels with pore networks replicating the geometry of real sandstone rock. The qualitative observations of phase transitions at pore-scale helped explain the flow rates measured at core-scale. This thesis consists of seven scientific papers presenting a detailed description of gas hydrates effect on fluid flow in porous media. The first step in every gas hydrate experiment is to establish gas hydrates in the pore space and this was particularly investigated in paper 1. The effect of heterogeneous water distribution on CH4 hydrate growth was resolved in Bentheim sandstone core plugs by MRI. The growth of CH4 hydrate was more profound in regions of the core plug saturated with high water content and the final CH4 hydrate distribution mirrored the initial water distribution. The same growth pattern of CH4 hydrate was observed in the micromodel in paper 2 and further developed into a conceptual growth model based on the initial pore-scale fluid distribution: A) A porous hydrate with encapsulated CH4 gas surrounded by a shell of CH4 hydrate formed in regions with high CH4 gas saturation. B) A solid nonporous hydrate with no CH4 gas formed in regions with low CH4 gas saturation. The final hydrate morphology was mainly governed by local availability of water and mass transfer of water/CH4 across the hydrate layer at the gas-water interface. In paper 3, the controlling mechanisms on the rate of CH4 gas recovery from CH4 hydrates were investigated via constant pressure dissociation in Bentheim sandstone core plugs. The maximum rate of CH4 gas recovery was governed by the CH4 hydrate saturation and the rate was highest in the CH4 hydrate saturation interval of 0.30 – 0.50 (frac.). The CH4 gas recovery was slower at higher CH4 hydrate saturation because of ineffective pressure transmission through the pore network and low relative permeability of the liberated CH4 gas. The relative permeability to CH4 (or CO2) in gas hydrate-filled sandstone rock was measured in paper 4. The addition of solid hydrates in the pore space reduced the effective permeability to both CH4 and CO2 at constant CH4 (or CO2) saturation. The fitting exponent, n, in the modified Brooks-Corey curve increased during hydrate growth for both CH4 and CO2. The exponent increased from 2.7 to 3.6 when CH4 hydrates formed in the pores and from 4.0 to 5.8 when CO2 hydrates formed. The effective permeability to CH4 (or CO2) was more sensitive to inclusion of hydrates in the pores at low CH4 (or CO2) saturations, most likely because the limited CH4 (or CO2) phase was more prone to become disconnected and capillary immobilized. The ability of CO2 hydrates to immobilize CO2 in water-saturated rock was explored in paper 5-7. The nature of CO2 hydrate sealing during CO2 injection was revealed at both micro- and core-scale in paper 5. Liquid CO2 was completely immobilized by surrounding CO2 hydrates that initially had formed at the CO2-water interface and then later crystallized the water phase into nonporous CO2 hydrates. The long-term sealing capability of the formed CO2 hydrates was tested for different rock core samples in paper 6-7. In quartz-dominated rock core plugs, the CO2 hydrate plug formed faster in tight rocks with low absolute permeability. Narrow pore throats in tight rocks were more easily obstructed by thin hydrate films that formed early in the nucleation process. The CO2 hydrate formed later in an Edwards limestone core plug (Kabs = 80 mD) than in a Bentheim sandstone core plug (Kabs = 1500 mD) despite having a lower absolute permeability. The leakage rate of CO2 through the CO2 hydrate plug was higher in the limestone core plug compared to the sandstone core plug. The CO2 hydrate self-sealing was therefore slower and less robust in carbonate rock compared to quartz-dominated rock

Quantification of CH4 Hydrate Film Growth Rates in Micromodel Pores

In this paper, we report the growth pattern and the rate of CH4 hydrate in sandstone pores. A high-pressure, water-wet, transparent micromodel with pores resembling a sandstone rock was used to visualize CH4 hydrate formation at reservoir conditions (P = 35–115 bar and T = 0.1–4.9 °C). The CH4 hydrate preferably formed and grew along the gas–water interface until the gas phase was completely encapsulated by a hydrate film. Two different growth rates were identified on the gas–water interface: CH4 hydrate film growth along the vertical pore walls (∼1200 μm/s) was more than 100 times faster than the film growth toward the pore center (∼8 μm/s). CH4 hydrate crystal growth directly in the water phase was slow and the rate was less than 0.5 μm/s. The film growth rate along the gas–water interface was independent of the pore size, gas saturation, and gas distribution, but the pore wall growth rate displayed a power law dependency on the applied subcooling temperature, ΔT, with a power law exponent equal to 2. The results of this study can be used as input to numerical models aiming to simulate pore-scale CH4 hydrate growth behavior.publishedVersio

Experimental Investigation of Critical Parameters Controlling CH4− CO2 Exchange in Sedimentary CH4 Hydrates

Sequestration of CO2 in natural gas hydrate reservoirs may offer stable long-term deposition of a greenhouse gas while benefiting from CH4 gas production. In this paper, we review old and present new experimental studies of CH4–CO2 exchange in CH4 hydrate-bearing sandstone core plugs. CH4 hydrate was formed in Bentheim sandstone core plugs to prepare for subsequent lab-scale CH4 gas production by CO2 replacement. The effect of temperature, diffusion length, salinity, water saturation, CH4 hydrate saturation, and co-injection of chemicals (N2 and monoethanolamine) with the injected CO2 were measured. The measurements prove the critical role of water saturation in these processes: formation of CO2 hydrate severely reduced the injectivity for water saturations above 0.1 fractions. The results presented in this paper are important when assessing natural gas hydrate reservoirs as candidates for CO2 injection with concurrent CH4 gas production.publishedVersio

Hydrate Plugging and Flow Remediation during CO2 Injection in Sediments

Successful geological sequestration of carbon depends strongly on reservoir seal integrity and storage capacity, including CO2 injection efficiency. Formation of solid hydrates in the near-wellbore area during CO2 injection can cause permeability impairment and, eventually, injectivity loss. In this study, flow remediation in hydrate-plugged sandstone was assessed as function of hydrate morphology and saturation. CO2 and CH4 hydrates formed consistently at elevated pressures and low temperatures, reflecting gas-invaded zones containing residual brine near the injection well. Flow remediation by methanol injection benefited from miscibility with water; the methanol solution contacted and dissociated CO2 hydrates via liquid water channels. Injection of N2 gas did not result in flow remediation of non-porous CO2 and CH4 hydrates, likely due to insufficient gas permeability. In contrast, N2 as a thermodynamic inhibitor dissociated porous CH4 hydrates at lower hydrate saturations (<0.48 frac.). Core-scale thermal stimulation proved to be the most efficient remediation method for near-zero permeability conditions. However, once thermal stimulation ended and pure CO2 injection recommenced at hydrate-forming conditions, secondary hydrate formation occurred aggressively due to the memory effect. Field-specific remediation methods must be included in the well design to avoid key operational challenges during carbon injection and storage.publishedVersio

Compressional wave phase velocity measurements during hydrate growth in partially and fully water saturated sandstone

The compressional wave phase velocity (cP) has been measured as a function of hydrate saturation (SH) during hydrate growth in Bentheim sandstone. The Fourier spectrum signal processing technique was used to specifically obtain the phase velocity at frequency 500 kHz. Eight experiments were conducted on eight Bentheim sandstone samples, having initial water saturation (Swi) in the range 0.51–1. Based on the measurements, it is discussed how Swi might affect the hydrate formation pattern during hydrate growth. For the sample having Swi = 0.51, a clear increase is observed in the measured cP from the beginning of the hydrate formation process. In the literature, micropore models ascribe such an increase to hydrates partly forming in soft, low aspect-ratio pores. For the samples having Swi ≥ 0.68, there is an initial stage in the hydrate formation process with little or no change in the measured cP. The SH interval defining this first stage seems to increase for increasing Swi. As SH further increase, a second stage follows where cP increases. This is explained with hydrates first forming as a hydrate-water slurry before eventually solidifying and taking part of the solid frame. The results aid in understanding how the elastic properties of hydrate-bearing porous rocks change with SH and Swi.publishedVersio

Experimental and Numerical Analysis of the Effects of Clay Content on CH4 Hydrate Formation in Sand

Natural gas hydrates exist in large quantities in nature and represent a potential source of energy, mostly in the form of methane gas. Knowledge about hydrate formation in clayey sand is of importance for understanding the production of methane gas from hydrate reservoirs, as well as for understanding the impact of global warming on the stability of subsurface gas hydrates. In this paper, we explore the effect of clay content on methane gas hydrate phase transitions in unconsolidated sand at realistic reservoir conditions (P = 83 bar and T = 5–8 °C) both experimentally and numerically. Kaolin clay was mixed in pure quartz sand in a series of experiments where the clay content ranged from 0 wt % to approximately 12 wt %. Simulations of these experiments were set up in TOUGH+HYDRATE. In the kinetic reaction model, particle size was used as a proxy for kaolin content. The growth of methane hydrates from water (0.1 wt % NaCl) and methane were visualized and quantified by magnetic resonance imaging with millimeter resolution. Dynamic imaging of the sand revealed faster hydrate growth in regions with increased clay content. NMR T2 mapping was used to infer the hydrate phase transition characteristics at the pore scale. Numerical simulations showed also faster growth in materials with a smaller mean particle size. The simulation results showed a significant deviation throughout the hydrate growth period. The constraints of both the experimental and modeling setups are discussed to address the challenges of comparing them.publishedVersio

Direct Visualization of CH4/CO2 Hydrate Phase Transitions in Sandstone Pores

This paper reports the formation and dissociation pattern of hydrate crystals with varying compositions of CH4 and CO2 in porous media. Direct visualization was carried out using a high-pressure, water-wet, silicon wafer-based micromodel with a pore network resembling sandstone rock. Hydrate crystals were formed under reservoir conditions (P = 45–65 bar and T = 1.7–3.5 °C) from either a two-phase system consisting of liquid water and a CH4–CO2 gas mixture or a three-phase system consisting of liquid water, CH4-rich gas, and CO2-rich liquid. A stepwise pressure reduction method was later applied to visualize multiple dissociation events occurring between the equilibrium pressures of pure CH4 hydrates and pure CO2 hydrates. The results showed that liberated gas from the initial dissociation became trapped and immobilized by surrounding undissociated hydrate crystals when the initial hydrate saturation was high. Mixing of liberated gas with liquid water led to rapid reformation of hydrates during the stepwise pressure reduction; the reformed hydrate crystals dissociated at a lower pressure close to the equilibrium pressure of pure CO2 hydrates. The results demonstrate the possibility of producing gas liberated from local hydrate dissociation while simultaneously reforming hydrates in other parts of the sediments. This is relevant for the proposed production method where CO2 injection in CH4 hydrate reservoirs is followed by pressure depletion to enhance the CH4 gas recovery.publishedVersio

Multiscale investigation of CO₂ hydrate self-sealing potential for carbon geo-sequestration

Storage of liquid CO2 in shallow geological formations is a recently proposed concept that can facilitate increased storage capacity and improved mobility control. If stored below the gas hydrate stability zone (GHSZ), unwanted vertical migration of CO2 can be effectively inhibited by the formation of solid hydrate layers. Lowering the risks of CO2 leakage to the atmosphere is instrumental to accelerate the implementation of full-scale carbon sequestration in the North Sea and elsewhere. In the laboratory, we have successfully visualized CO2 trapping phenomena, measured CO2 leakage rates, and demonstrated that the integrity of the hydrate seal strongly depends on fluid-rock interactions and initial water distribution. CO2 propagation in water-filled core samples has been monitored over a total of 140 days inside the GHSZ. Solid CO2 hydrate formed and sealed the pore space in both homogeneous sandstone and heterogeneous limestone cores. However, the physical flow barrier developed considerably faster in sandstone (after 1.8 pore volumes – PV) compared to limestone (after 7.4 PV), with a factor ten reduced CO2 leakage rate through the seal in favor of sandstone. Furthermore, pore-scale images of upward CO2 migration verified trapping of CO2 both as solid hydrate precipitation and as liquid CO2 clusters made discontinuous and stabilized by capillary forces. Small-scale hydrate rearrangement followed initial formation, and caused temporarily dissociation of local hydrate structures without affecting the overall integrity of the seal. Our study suggests that a homogeneous, water-filled GHSZ directly above a CO2 storage site can provide a secondary safety mechanism and significantly reduce the risk of CO2 leakage.publishedVersio