An oscillating drop rheometer capable of operating under conditions of high pressure and high temperature has been built. The oscillating drop mechanism was able to support pressures as high as 1300 bar and successfully performed oscillations at constant pressure. Apparent elastic and viscous complex moduli were measured for a system of CO2 and synthetic seawater containing 100 ppm of a linear alkyl ethoxylate surfactant for different pressures and temperatures. The moduli had strong dependencies on both pressure and temperature. At temperatures of 40 and 80 °C, the apparent elastic modulus passed through a maximum for pressures between 100 and 300 bar. The harmonic distortion of the oscillations was calculated for all measurements, and it was found that drop oscillations below ca. 2.6 µL caused distortions above 10% due to a mechanical backlash of the motor.

Convective mixing of free-phase CO2 and brine in saline aquifers is an established technique to accelerate the CO2 dissolution process. Correct estimation of the convection onset time and rate of CO2 dissolution into brine are two crucial parameters regarding safety issues, as the timescale for dissolution corresponds to the same time over which the free-phase CO2 has a chance to leak out from the storage site. In real practice, underground formations are heterogeneous with a layered structure, but the convective mixing in heterogeneous porous media has received less attention than the homogeneous one. This study aims to develop a basic understanding of the role of layered permeability media (layered structure with variation in permeability vertically) on the behavior of convective mixing via well-controlled laboratory experiments. The effects of layering and layer properties on the rate of dissolution of CO2 in water and geometries of the formed convection fingers are studied using a precise experimental set-up with layered-permeability Hele-Shaw cell geometry. Qualitative (snapshots of convection fingers) and quantitative data (amount of the dissolved CO2 into water) are collected simultaneously for a better understanding of the process. The behavior of convection fingers (after the onset of convection) and the effects of model properties on this mixing process are also discussed.

The partitioning of non-ionic surfactants in a CO2/synthetic brine system was studied for a selection of surfactants at reservoir conditions for CO2 enhanced oil recovery and aquifer storage. Alkyl and alkylphenol ethoxylates with different degrees of branching in their hydrophobic moiety were chosen. Generally, higher temperature and pressure promoted increased solubility in CO2. Branching of the hydrophobic moiety tends to favour CO2 solubility (higher partition coefficient). Highly branched moieties were found to hinder solubility probably due to a decrease of their conformational entropy. The addition of an aromatic ring connecting the ethoxylate moiety and the hydrophobic moiety seemed to have an adverse effect at lower temperatures. For two surfactants, the effect of concentration on partitioning was also studied. The partition coefficient decreased for increasing concentrations until a plateau was reached above the corresponding surfactant critical micelle concentration (CMC). This may indicate micelle formation both in the CO2 and in the aqueous phase.

With present emissions the global CO2 budget associated with a maximum temperature increase of about 1.5–2 °C will likely be spent within a few decades, Thus, it will be very difficult or perhaps even impossible to meet the climate targets agreed upon in Paris only by decreasing emissions of greenhouse gases. Scenarios presented in the IPCC reports accommodate for this by introducing so-called negative CO2 emissions. The idea is that the cumulative CO2 emission budget will be exceeded, but that massive negative emissions, especially during the latter part of the century, will remove the surplus of CO2 in the atmosphere. A number of different Negative Emissions Technologies (NETs) have been proposed, including Biomass Energy with Carbon Capture and Storage (BECCS), afforestation/reforestation, altered agricultural practices, biochar production, enhanced weathering and direct air captured. However, many of the options proposed could be associated with carbon leakage which could compromise the purpose of negative emissions, e.g. storage in of carbon in growing/dead biomass that leaks to the atmosphere. Furthermore, it may be difficult to safely assess the long-term leakage rates. To reach the large negative emissions needed it is expected to require a mix of approaches having different expected retention times, and different safety in terms of leakage rates. Could the risk of leakage mean that we are just delaying the problem and transferring the problem to coming generations? The short answer to this is that it all depends on the leakage rates. Different leakage rates and mixes of leakage rates are investigated in the paper. For the case of a mixture of leakage time scales of 300, 1000 and 10,000 years and assuming that 80% or more was permanently stored, the contribution to the atmospheric stock was small, peaking at about 3 ppm CO2. It was concluded that leakage would not significantly compromise the benefits of negative emissions unless leakage is substantial and rapid. To quantify what could be meant by substantial and rapid, an example would be if 100% of the CO2 stored would leak out at a rate of the order of 1%/year.

Graphene oxide (GO), nanographene oxide (nGO) and partially reduced graphene oxide (rGO) have been studied as possible foam stabilizing agents for CO2 based enhanced oil recovery (EOR). GO was able to stabilize CO2/synthetic sea water foams. rGO was not able to stabilize foams likely due to the high reduction degree of the material. Particle size had a strong influence on foamability and stability. GO hydrophilicity increased as the particle size decreased and no foams were created when particle size was below 1 µm (nGO). GO brine dispersions showed immediate gel formation, which improved foam stability. Particle growth due to layer stacking was also observed. This mechanism was detrimental for foam formation and stabilization. nGO dispersed in synthetic sea water rapidly formed hydrogels and was not filterable. This work indicates that the particles studied are not suitable for CO2 EOR purposes.

Graphene oxide, nanographene oxide and partially reduced graphene oxide have been studied as possible foam stabilizing agents for CO2 based enhanced oil recovery. Graphene oxide was able to stabilize CO2/synthetic sea water foams, while nanographene oxide and partially reduced graphene oxide were not able to stabilize foams. The inability of nanographene oxide for stabilizing foams was explained by the increase of hydrophilicity due to size decrease, while for partially reduced graphene oxide, the high degree of reduction of the material was considered to be the reason. Graphene oxide brine dispersions showed immediate gel formation, which improved foam stability. Particle growth due to layer stacking was also observed. This mechanism was detrimental for foam stabilization. Gel formation and particle growth caused these particles to block pores and not being filterable. The work indicates that the particles studied are not suitable for CO2 enhanced oil recovery purposes.

Graphene oxide (GO), nanographene oxide (nGO) and partially reduced graphene oxide 9 (rGO) have been studied as possible foam stabilizing agents for CO2 based enhanced oil recovery 10 (EOR). GO was able to stabilize CO2/synthetic sea water foams. rGO was not able to stabilize foams 11 likely due to the high reduction degree of the material. Particle size had a strong influence on 12 foamability and stability. GO hydrophilicity increased as the particle size decreased and no foams 13 were created when particle size was below 1 μm (nGO). GO brine dispersions showed immediate 14 gel formation, which improved foam stability. Particle growth due to layer stacking was also 15 observed. This mechanism was detrimental for foam formation and stabilization. nGO dispersed 16 in synthetic sea water rapidly formed hydrogels and was not filterable. This work indicates that the 17 particles studied are not suitable for CO2 EOR purposes. 18

CO2 dissolution is considered as one of the most promising mechanisms for trapping of free-phase CO2 into brine. It causes an increased density of the brine and initiation of gravitational instability that eventually leads to density-driven natural convection in saline aquifers. Correct estimation of the onset time for convection and the rate of dissolution of CO2 into brine is important because the timescale for dissolution corresponds to the timescale over which free-phase CO2 has a chance to leak out. The gravitational instability of a diffusive boundary layer in porous media has been studied in several papers in recent years, but there are few works about the behavior of density-driven natural convection mechanism in heterogeneous saline aquifers. Barriers such as shales and calcites layers are common types of heterogeneities in geological formations that are important in the fluid flow. Despite the recognized importance of convective dissolution in these heterogeneous geological formations, there is no experimental data available for studying the accelerated mass transfer rate of CO2 into these media. In this paper, we investigated the effect of the regular distribution of barriers on the rate of dissolution of CO2 into water and geometries of convection fingers. A series of experiments were performed using a precise experimental set-up with barrier heterogeneous Hele-Shaw cell geometries and by using CO2 and water. The approach and procedure for performing the experiments give us this opportunity to have both qualitative (images and movies) and quantitative (amount of the dissolved CO2 into water) data at the same time. The behavior of convection pattern after onset time and the effect of system properties on the behavior of convective mixing process will be presented and discussed. Moreover, some speeded-up movies from the experiments that are suitable for improving public awareness of the problem have been uploaded on the internet platform. Lastly, the relationships between dissolution flux after onset time for convection and barrier properties are discussed.

An experimental setup has been designed for measuring the dissolution rate of buoyant CO2 into the water phase below. Experiments were performed in a high-pressure cell, where the water phase was stabilized by a porous medium to mimic the situation of a gas cap in a storage reservoir. As many previous tests have been performed in 2D cells, this setup allows for 3D measurements of diffusion-induced convection. The tests are performed at high pressure where CO2 is at high density, similar to a real storage situation and the dissolved CO2 is measured by metering the pump that is automatically maintaining constant pressure. This allows rate measurements in a 3D environment. The basic interest was to determine the dissolution rate in the convective regime, but also the diffusion coefficient of CO2 in water was determined by this experimental setup. In addition, the onset time of convection was estimated. The result show that the dissolution rate measured during convection was one to two order of magnitude faster than predicted by semi-empirical correlations obtained by numerical simulations. The estimated onset time of convection was shorter than theoretical prediction. The overall results suggests that diffusion induced convection plays a more important role than previously assumed.

A technical-economical model for a large-scale infrastructure combining CO2 EOR and aquifer storage has been used to construct a scenario including 23 Norwegian Continental Shelf oil fields that have been identified as potential candidates for CO2 flooding. In the injection scenario, 70 million tonnes of CO2 is injected annually over 40 years. A limited sensitivity analysis has been performed. The EOR potential for continuous CO2 injection is estimated to be between 276 and 351 million Sm3. This corresponds to 5.9 and 7.6% of the oil originally in place depending on the oil price (low/high: 40/120 USD/bbl), the cost of CO2 that the oil producers must pay for all stored CO2 (low/high: 0/50 USD/tonne) and well costs (low/high 25/42 million USD/well). In addition to transportation costs through the main pipeline (8 USD/tonne) specific costs for aquifer deposition also applies (8 USD/tonne). CO2 mass balance calculations show that more CO2 is stored in the oil reservoirs during tertiary flooding compared to the CO2 formed by combustion of the produced oil. The CO2 footprint becomes even more negative when the CO2 stored in aquifers is included in the calculations.

The Aliso Canyon gas well leakage is used as an analogue to study a possible accident from a CO2 storage site. Because the blowout is the second largest in USA, it can be used as a worst-case blowout analogue for a possible CO2 blowout from an underground CO2 storage. Reservoir modelling and well modelling of the Aliso Canyon case is used to determine the leakage pathway and leakage mechanisms that will mimic the escape history. This data are put in a new model where the gas is replaced by CO2 and a similar accident is simulated. Several factors are different between gas leakage from gas storage and potential leakage from a typical CO2 storage in an aquifer, due to differences in thermodynamic properties and flow properties both along in the leakage pathway and in the porous medium in the storage reservoir. The specific features of the two cases are compared and show that as the risk elements are very different, remediation measures will be different. The escape rate is significant lower for the CO2 scenario than the observed gas escape from Aliso Canyon gas well (4.9 Sm3/s respectively 21.3 Sm3/s). While 2.8% of the stored gas was lost at the Aliso Canyon leak, the corresponding loss from a CO2 well if the facility was used for CO2 storage would be 0.37%. Due to the high density of CO2, the well pressure at the rupture was less than half than for CO2 compared to gas, which will make remediation easier.

Long term success of CO2 storage is heavily dependent on maintaining well integrity. Prevention and remediation of leakage through wells plays a crucial role in large scale implementation of CO2 storage. Squeeze cementing is the most common remediation practice in the oil and gas industry used for various well leakage scenarios. The objective of this work was to test the sealing ability of a commercially available temperature-activated polymer resin in a laboratory-scale squeeze cementing operation. Two well leakage scenarios were selected: micro-annuli or cracks in cement and debonding at cement-casing interface. Cement (with or without steel) core samples with designed vertical leak paths were prepared. Permeability of the samples was measured both before and after the squeeze procedure. Then the samples were disassembled and studied by optical microscopy. The squeeze procedure proved to be successful for plugging the designed leak paths.

Fast implementation of CO2 storage on a large scale is needed to meet the international targets on reduced CO2 emissions. In the absence of a commercial market, Norwegian R&D actors have formulated a vision that implies storage of more than 10 million tons CO2 per year on the Norwegian shelf. The purpose is to restore the momentum of CCS research, to direct and coordinate on-going and future efforts to develop the technology, and to motivate industry and authorities to engage in a more forceful schedule for CCS deployment. Based on a review of technology needs, a case-based study is proposed to apply and improve the knowledge and technologies needed by industry to undertake field development studies by 2018.

Sequestration of CO2 in a saline aquifer is currently being evaluated as a possible way to handle CO2 emitted from a coal-fueled power plant in Svalbard. The chosen reservoir is a 300-m thick, laterally extensive, shallow marine formation of late Triassic-mid Jurassic age, located below Longyearbyen in Svalbard. The reservoir consists of 300 m of alternating sandstone and shale and is sealed by 400 m of shale. Experimental and numerical studies have been performed to evaluate CO2 storage capacity. A total of 51 samples of core material from one well (Dh4) were collected and tested to find the potential units for CO2 injection. Analysis of the results shows that the permeability is generally less than 2 millidarcies and the capillary entry pressure is high. This poses a serious challenge with respect to achieving practical levels of injectivity and injection pressure. For further investigation, two 32-cm-long sandstone samples from the depth 675 m (Sample 1) and 679 m (Sample 2) were selected for laboratory core flooding experiments at reservoir conditions. This review presents the experimental protocol and detailed CO2-brine drainage and imbibition relative permeability data for these two different samples of rock. Capillary pressure measurements and simulation of the transient process was used to support the interpolation of the experimental flooding data. Initial x-ray computed tomography scan showed no sign of fractures inside the cores, whereas after the core flooding experiment, there were visible fractures especially in Sample 1. Scanning electron microscopy analysis showed a high proportion of diagenetic iron-minerals in the sandstones like Fe-chlorite, Fe-carbonate (FeCO3), and pyrite (FeS2). A brownish output flow was seen in the sample with highest porosity and permeability. Dissolution of CO2 in the brine forms a weak acid that reacts with iron-minerals (e.g. siderite) to form iron-hydroxides. Severe hysteresis effects on one of the samples most likely resulted from changes in the rock composition.

Changes in wettability have been quantified by measuring the CO2 contact angle on some selected minerals typical for reservoir rocks quartz, calcite and feldspar, in the presence of brine at reservoir conditions - by use of the captive-needle drop method. Also wettability alteration of the CO2 as a function of time was investigated.No significant change in contact angle was observed for any of the minerals as function of pressure and only small variation with change in temperature and salinity. All mineral surfaces remained strongly water-wet. A minimum in contact angle was observed at 36 degrees C near the critical pressure, which could be related to the near-critical behavior of the CO2-phase. Exposing the calcite mineral to CO2 for 50 days at fixed conditions did not cause any significant change in water wettability. (c) 2013 The Authors. Published by Elsevier Ltd.

Digital pore scale images of the reservoir rocks from the Utsira formation have been modelled. The Utsira Formation on the Norwegian Continental Shelf that is already being used for CO2 sequestration. This is a saline sand aquifer of Miocene to early Pliocene age, which is covered by some 700 meters of shales and sands. The aquifer is large and CO2 is being injected into the aquifer at a depth of 1012 meters below the sea floor by a highly deviated 3 km long well from the Sleipner Field. Direct dynamic CO2/water simulations have been conducted with all relevant fluid and flow properties. From these simulations steady and un-steady state constitutive relations (relative permeability, end-point saturations) are obtained. Clear flow rate and viscosity effects are revealed from these data, which again affects the storage capabilities of the reservoir rocks.

A field laboratory for monitoring CO2 migration has been established in the Holocene deposit of the Svelvik ridge, located at the sill of the Drammensfjord 50km south of Oslo. Initial characterization of the site shows that the formation is very suitable for studying migration and associated leakage, particularly within the top 50 m where the sediments consist of relatively homogenous sand. In the deeper part of the deposit, the formation seems to have more structure possibly enabling monitoring of horizontal migration and more complex migration patterns.