Arne Graue

Storage of CO2 in natural gas hydrate reservoirs and the effect of hydrate as an extra sealing in cold aquifers

Abstract Reservoirs of clathrate hydrates of natural gases (hydrates), found worldwide and containing huge amounts of bound natural gases (mostly methane), represent potentially vast and yet untapped energy resources. Since CO2-containing hydrates are considerably more stable thermodynamically than methane hydrates, if we find a way to replace the original hydrate-bound hydrocarbons by the CO2, two goals can be accomplished at the same time: safe storage of carbon dioxide in hydrate reservoirs, and in situ release of hydrocarbon gas. We have applied the techniques of Magnetic Resonance Imaging (MRI) as a tool to visualize the conversion of CH4 hydrate within Bentheim sandstone matrix into the CO2 hydrate. Corresponding model systems have been simulated using the Phase Field Theory approach. Our theoretical studies indicate that the kinetic behaviour of the systems closely resembles that of CO2 transport through an aqueous solution. We have interpreted this to mean that the hydrate and the matrix mineral surfaces are separated by liquid-containing channels. These channels will serve as escape routes for released natural gas, as well as distribution channels for injected CO2.

Using magnetic resonance imaging to monitor CH4 hydrate formation and spontaneous conversion of CH4 hydrate to CO2 hydrate in porous media

Magnetic resonance imaging was used to monitor and quantify methane hydrate formation and exchange in porous media. Conversion of methane hydrate to carbon dioxide hydrate, when exposed to liquid carbon dioxide at 8.27 MPa and approximately 4 degrees C, was experimentally demonstrated with MRI data and verified by mass balance calculations of consumed volumes of gases and liquids. No detectable dissociation of the hydrate was measured during the exchange process.

Volatile organic acids produced during kerogen maturation— amounts, composition and role in migration of oil

Abstract Maturation dependent generation of organic compounds from North Sea source rocks has been investigated by hydrous pyrolysis of powdered source rock samples. The generation of water soluble organic acids is emphasised, and their composition compared with oil-field water samples. Similar compositions are found. Matrix adsorption effects are not found to be quantitatively important. Timing of acid generation relative to oil generation is discussed. Effects of realistic concentrations of a volatile organic acid in the water phase on interfacial tension is determined, and effects on fluid flow of crude oil through water-saturated sandstone is investigated using a long-core flow-rig.

Kinetics of solid hydrate formation by carbon dioxide: Phase field theory of hydrate nucleation and magnetic resonance imaging

In the course of developing a general kinetic model of hydrate formation/reaction that can be used to establish/optimize technologies for the exploitation of hydrate reservoirs, two aspects of CO2 hydrate formation have been studied. (i) We developed a phase field theory for describing the nucleation of CO2 hydrate in aqueous solutions. The accuracy of the model has been demonstrated on the hard-sphere model system, for which all information needed to calculate the height of the nucleation barrier is known accurately. It has been shown that the phase field theory is considerably more accurate than the sharp-interface droplet model of the classical nucleation theory. Starting from realistic estimates for the thermodynamic and interfacial properties, we have shown that under typical conditions of CO2 formation, the size of the critical fluctuations (nuclei) is comparable to the interface thickness, implying that the droplet model should be rather inaccurate. Indeed the phase field theory predicts considerably smaller height for the nucleation barrier than the classical approach. (ii) In order to provide accurate transformation rates to test the kinetic model under development, we applied magnetic resonance imaging to monitor hydrate phase transitions in porous media under realistic conditions. The mechanism of natural gas hydrate conversion to CO2-hydrate implies storage potential for CO2 in natural gas hydrate reservoirs, with the additional benefit of methane production. We present the transformation rates for the relevant processes (hydrate formation, dissociation and recovery).

MRI Visualization of Spontaneous Methane Production From Hydrates in Sandstone Core Plugs When Exposed to CO2

Magnetic resonance imaging (MRI) of core samples in laboratory experiments showed that CO2 storage in gas hydrates formed in porous rock resulted in the spontaneous production of methane with no associated water production. The exposure of methane hydrate in the pores to liquid CO2 resulted in methane production from the hydrate that suggested the exchange of methane molecules with CO2 molecules within the hydrate without the addition or subtraction of significant amounts of heat. Thermodynamic simulations based on Phase Field Theory were in agreement with these results and predicted similar methane production rates that were observed in several experiments. MRI-based 3D visualizations of the formation of hydrates in the porous rock and the methane production improved the interpretation of the experiments. The sequestration of an important greenhouse gas while simultaneously producing the freed natural gas offers access to the significant amounts of energy bound in natural gas hydrates and also offers an attractive potential for CO2 storage. The potential danger associated with catastrophic dissociation of hydrate structures in nature and the corresponding collapse of geological formations is reduced because of the increased thermodynamic stability of the CO2 hydrate relative to the natural gas hydrate.

Systematic wettability alteration by aging sandstone and carbonate rock in crude oil

Abstract A reproducible method for selectively altering the wettability of outcrop chalk has been established to obtain stable wettability conditions in the range from strongly water-wet to near-neutral-wet. Aging in different oils and the response to aging in different rocks are reported. The influence of different initial water saturations on the role of wettability alterations has been evaluated. Core plugs were aged in oil, at 90°C, for different time periods in duplicate sets. Oil recovery by spontaneous room temperature imbibition, followed by a waterflood, was studied for aged cores, to obtain Amott–Harvey wettability index to water. The procedure was also performed on cores containing aged crude oil, on cores where the aged crude oil was exchanged with fresh crude oil after aging was completed, but before imbibition testing and for cores where the crude oil was exchanged with decahydronaphthalene which was then displaced by n -decane. Imbibition in water-wet cores with n -decane was used as the baseline experiment. A consistent and reproducible change in wettability, from strongly water-wet to a near-neutral-wet state, with increased aging time was observed for five different outcrop chalks. The altered wettability was stable over several flooding cycles but when the aged crude oil was exchanged by fresh crude oil or decane after aging but before imbibition, results exhibited different but consistent Amott indices. Exchanging crude oil at temperature with decalin, which in turn was exchanged with decane, was found to be the best procedure for reproducible and stable wettability alteration.

Alteration of wettability and wettability heterogeneity

Abstract This paper emphasizes how wettability may be altered for special core analysis purposes and by which processes this occurs. Studies of how the imbibition characteristics change after aging core plugs in crude oil are reported, focusing on imbibition rate and endpoint saturations and on the induction time. Imbibition characteristics after wettability alteration by aging core plugs submerged in crude oil at elevated temperature are compared to the effects from aging procedures, where crude oil is continuously flushed through the core plugs during the aging and after simply leaving the plug at connate water saturation under static, i.e. no flow conditions, shows different significant results. The results show that: (1) continuously introducing fresh crude oil boosts the aging process and (2) a significant impact on the wettability alteration as a function of core length is observed, reflecting the absorption of active components for the wettability alteration process. In an integrated study consisting of experiments and numerical simulation, this paper also demonstrates the importance of close interaction between how to alter the wettability, applications of the technique in core analysis and numerical simulations of the latter. Finally, the significance of some sensitive parameters is demonstrated.

Wettability Effects on Oil-Recovery Mechanisms in Fractured Reservoirs

The effects of fractures on oil recovery and in-situ saturation development in fractured chalk blocks have been determined for several representative wettabilities. These effects were visualized using two complimentary two-dimensional in-situ imaging techniques; nuclear tracer imaging (NTI) for the experiments with large blocks of chalk and magnetic resonance imaging (MRI) for high spatial resolution to visualize fluid flow patterns inside fractures between two stacked core plugs. For three different wettabilities, the specific patterns of saturation development were monitored with NTI and the mechanisms of fracture crossing were determined using MRI.

Experimental Investigation of Enhanced Recovery in Unconventional Liquid Reservoirs using CO2: A Look Ahead to the Future of Unconventional EOR

The poor rock quality and matrix permeability several orders of magnitude lower than conventional oil reservoirs observed in unconventional liquid reservoirs (ULR) presents many uncertainties on the storage capacity of the rock and the possibility of enhancing recovery. The technological advances in multiple stage hydraulic fracturing and horizontal drilling have improved the overall profitability of oil shale plays by enhancing the matrix – wellbore connectivity. The combination of these technologies has become the key factor for the operators to reach economically attractive production rates in the exploitation of ULR, causing a lot of focus on their improvement. However, as the reservoir matures, primary production mechanisms no longer drive oil to the hydraulic fractures, making the improvement of matrix – wellbore connectivity insufficient to provide economically attractive production rates. Therefore, the need to develop enhanced recovery techniques in order to improve the displacement of the oil from the matrix, maintain profitable production rates, extend the life of the assets and increase ultimate oil recovery becomes evident. This study presents experimental results on the use of CO2 as an enhanced oil recovery (EOR) agent in preserved, rotary sidewall reservoir core samples with negligible permeability. To simulate the presence of hydraulic fractures, the ULR cores were surrounded by high permeability glass beads and packed in a core holder. The high permeability media was then saturated with CO2 at constant pressure and temperature during the experiment. Production was monitored and the experiment was imaged using x-ray computed tomography to track saturation changes inside the core samples. The results of this investigation support CO2 as a promising EOR agent for ULR. Oil recovery was estimated to be between 18 to 55% of OOIP. We provide a detailed description of the experimental set up and procedures. The analysis of the x-ray computed tomography images revealed saturation changes within the ULR core as a result of CO2 injection. A discussion about the mechanisms is presented, including diffusion and reduction in capillary forces. This paper opens a door to the investigation of CO2 enhanced oil recovery in ULR.

Activity of Sulfate-Reducing Bacteria Under Simulated Reservoir Conditions

This paper reports on sulfate-reducing bacteria (SRB) that have been isolated from hot oilfield waters from subsea oil reservoirs in the North Sea. Experiments with these bacteria in a reservoir simulator indicate that SRB may maintain their activity in the conditions found in most North Sea reservoirs and, if precautions are not taken, may contribute to souring of the oil and gas.