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Wind power can replace power from gas turbines and thus reduce the CO2 emissions related to oil production. However, a main challenge with wind power is the variability in power production due to weather variations. The water injection pumps are often major power consuming units. The water pumps were therefore identified as possible non-critical loads in an isolated power system with variable power supply. The power to a non-critical load can be varied and even stopped depending on the power supply. The objective of the present work was to study how variable water injection rates affects oil production. Using simulated wind power curves, water injection profiles for a model oil field were constructed. Reservoir simulations show that the oil production is almost insensitive to variable injection rates if the injected volumes were the same. Lower injected rates and volumes resulted in lower oil production. This was most pronounced in the plateau phase of the production, but later the differences become gradually smaller. Thus, reducing the water injection volumes with 30 % decreased the total oil recovery by less than 5 % after 28 years. If constant water injection rates are needed thermal power can supply wind power. This will increase the CO2 emissions. However, if wind power not used by the water injection pumps can be utilised for other unit operations significant reductions in CO2 emission can still be obtained.

Laboratory core flooding experiments performed are used to predict fluid flow behaviour in the reservoir. Most reservoirs are in a reduced state. However, iron minerals in the extracted cores may become oxidized going from the reservoir to the laboratory. Oxidation of the core can affect wettability and thereby relative permeability curves used for reservoir simulation studies. The aim of this work was to study the potential effect of core oxidation on relative permeability. Steady state relative permeability experiments with in-situ saturation measurements and use of live oil have been performed on one composite core at 10 different saturations. The core was tested under three different conditions: oxidized (Exp. 1), reduced (Exp. 2) and re-oxidised (Exp. 3). The core was cleaned, fluid saturated and aged before each test. In Exp. 2, the core plug was chemically reduced. All fluids used in this experiment were oxygen free. In Exp. 3 the core plug was treated using fluids to oxidise the core. Fluids injected and extracted, and core samples were analysed using a range of methods. Results showed that the measured relative permeability curves from Exp. 2 and 3 were similar and significantly different from the results from Exp. 1. The attempt to restore the core material to the initial state (oxidized) after Exp. 2 by exposing the core material to fluids with oxygen was seemingly not successful. The observation was also supported by unsteady state flooding measurements which indicated that as long as the core remained fluid saturated, it behaved as a reduced core, even after extensive exposure to oxygen containing liquids. The crossing point of the oil and water relative permeabilities indicate that the core was more water wet in reduced state compared to before the oxidized state. Differences in chemical composition were also detected between extracts from Exp. 1 - 3. The conclusion is that significant differences in steady state relative permeabilities of oil and water in oxidized and reduced states were observed for the iron containing core investigated. The results also indicate that if the core is kept fluid saturated, effects of oxidation may be significantly delayed.

The use of energy and the possibilities for energy recovery from pressurised fluid streams has been analysed for a petroleum production plant connected to an undersaturated oil field that was produced by water injection. The plateau production of oil was 15900 Sm3/d and water was injected at a rate of 20670 m3/d. The produced fluids arrived at the production plant at a relatively high pressure and temperature (70 bar and 82 °C). Produced oil and gas were continuously exported from the plant at 200 bara. The power consumption in the plant could be reduced by using equipment with high efficiency. The average power over the 27-year lifetime of the field was reduced from 19.95 MW to 14.78 MW for two scenarios using different equipment. This corresponds to a reduced energy consumption and reduced CO2 emissions of 986 million kWh and 692502 tonnes, respectively. Energy can be recovered from pressurized process streams. For the hydrocarbon streams in the plant turbogenerators were considered. Pressure from produced water could be recovered by use of pressure exchangers. On average 2 MW power was recovered over the lifetime of the field, saving 486 million kWh electric energy corresponding to 341166 tonnes CO2 emissions. All energy savings above apply both to plants powered by gas turbines and electrified fields. CO2 emissions per unit of potential combustion energy from produced petroleum was very low in the plateau phase of the production. Only late in the lifetime of the field the emissions approached and exceeded (depending on scenario) the average emissions of 5 g CO2/MJ for fields on the Norwegian Continental Shelf. The high potential for reduced energy consumption in the petroleum production plant and for energy recovery was due to the relatively high inlet pressures to the plant and high pressures of injected water. For lower inlet pressures and better water injectivity the potential will be lower, and fields should be studied case by case. Factors such as weight and space requirements of new alternative process equipment, cost and maintenance have not been considered in this work. In an electrified field the abundant supply of thermal energy from gas turbine exhaust will not be available. Thermal energy was available from the produced fluids and from the petroleum processing and could be sufficient e.g. for heating of housing areas and heating of process streams. If higher temperatures were needed heat pumps can be taken into use. Dedicated and field specific studies regarding use and recovery of thermal energy and possible applications of heat pumps must be done to find optimal solutions for the thermal energy demand of an electrified field, however.

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.

This work presents results from simulation of core-flooding experiments with several commercially available surfactants for CO2-foam stabilisation, potentially applicable for CO2 mobility control in CO2 storage operations. The simulations are run with a CO2 foam module for MRST, based on a foam effect model developed by Vassenden and Holt. Efficient use of mobility control for CO2 at field scale could give a significant increase in storage capacity. It could counter the negative effects of the mobility contrast between injected CO2 and the resident formation brine, enabling more optimal filling of structural traps and delaying breakthrough of injected CO2 at wells where formation brine is extracted for pressure management purposes. Efficient mobility control and the associated sweep improvement can more than double the storage efficiency in a developed five-spot pattern of injection and pressure control wells. Partitioning of surfactant between the CO2 and brine phases will lead to gradually reduced surfactant concentration and eventually loss of foam-generation as the CO2 penetrated deeper into the reservoir. Adsorption of surfactant to mineral surfaces will also contribute to the reduced concentration. Investigation of realistic field-scale effects of mobility control by foam requires both careful measurement of partitioning and adsorption properties in laboratory experiments and a reservoir simulator capable of including such effects.

Reduction of the CO2 mobility is beneficial during subsurface sequestration of anthropogenic CO2 in saline aquifers and hydrocarbon reservoirs by mitigating flow instabilities leading to early gas breakthrough and poor sweep efficiency. Injection of CO2 foam is a field-proven technology for gas mobility control. Foam generation and coalescence are compared between six commercially available surfactants with a range in CO2 solubility, during unsteady state injection of dense CO2-foam in a long sandstone outcrop core (1.15 m). Foam generation categories and foam decay were defined based on the observed changes in foam apparent viscosity during generation and coalescence. The degree of CO2 solubility influenced apparent viscosity development and peak foam strength for the tested surfactants. Variations in foam peak strength resulted in a range of water saturations at CO2 breakthrough (up to 24 percentage points difference observed experimentally), with implications for the CO2 storage capacity. publishedVersion

Foam can reduce CO2 mobility to improve the sweep efficiency during injection into subsurface geological formations for CO2 storage and enhanced oil recovery. However, CO2 foams are thermodynamically unstable, so they must be stabilized. Surfactants are often used to generate and stabilize foams in porous media and can be soluble in the aqueous phase, or in the CO2 phase. Aqueous- and CO2-soluble surfactants must be characterized for their ability to reduce CO2 mobility and stabilize foam at reservoir conditions. In addition, numerical models are necessary to predict and evaluate the effect of foam for field-scale applications and require empirical data obtained from core-scale flooding experiments. This study presents a series of steady-state foam co-injections with dense phase CO2 and either aqueous- or CO2-soluble surfactant solutions at varying CO2 flow velocities and CO2 fractions. One anionic water-soluble surfactant, which is considered a benchmark foam stabilizer, and five partially CO2-soluble non-ionic surfactants were investigated. Gamma ray attenuation was used to accurately monitor in-situ saturations during steady-state co-injections. The primary objective was to determine the steady-state foam characteristics of the different surfactants by evaluating the mobility reduction factor (MRF) and the limiting water saturation where foam abruptly collapses ( S w ∗ ). All of the tested surfactants generated foam and reduced CO2 mobility by more than three orders of magnitude. The anionic surfactant increased foam stability at lower water saturations, compared to the non-ionic surfactants, which resulted in lower residual water saturations and increased pore volume available for CO2 storage. Core flooding results provided input into a local-equilibrium foam model. The fitted foam model reproduced the experimental results for the anionic surfactant and for three of the five non-ionic surfactants. The two latter non-ionic surfactants violated model assumptions because non-monotonic water saturation changes were observed, an effect not accurately captured by local-equilibrium foam models. However, the modelling work elucidated subtle experimental trends and demonstrated the applicability of the dataset as input into implicit-texture local-equilibrium foam models.

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.

The application of nanotechnology to the petroleum industry has sparked recent interest in increasing oil recovery, while reducing environmental impact. Nanocellulose is an emerging nanoparticle that is derived from trees or waste stream from wood and fiber industries. Thus, it is taken from a renewable and sustainable source, and could therefore serve as a good alternative to current Enhanced Oil Recovery (EOR) technologies. However, before nanocellulose can be applied as an EOR technique, further understanding of its transport behavior and retention in porous media is required. The research documented in this paper examines retention mechanisms that occur during nanocellulose transport. In a series of experiments, nanocellulose particles dispersed in brine were injected into sandpacks and Berea sandstone cores. The resulting retention and permeability reduction were measured. The experimental parameters that were varied include sand grain size, nanocellulose type, salinity, and flow rate. Under low salinity conditions, the dominant retention mechanism was adsorption and when salinity was increased, the dominant retention mechanism shifted towards log-jamming. Retention and permeability reduction increased as grain size decreased, which results from increased straining of nanocellulose aggregates. In addition, each type of nanocellulose was found to have significantly different transport properties. Experiments with Berea sandstone cores indicate that some pore volume was inaccessible to the nanocellulose. As a general trend, the larger the size of aggregates in bulk solution, the greater the observed retention and permeability reduction. Salinity was found to be the most important parameter affecting transport. Increased salinity caused additional aggregation, which led to increased straining and filter cake formation. Higher flow rates were found to reduce retention and permeability reduction. Increased velocity was accompanied by an increase in shear, which is believed to promote breakdown of nanocellulose aggregates. © 2018 by the authors. Funding details: CERC35, CERC, Canada Excellence Research Chairs, Government of Canada; Funding details: 974 767 880; Funding details: 262644, I-CORE, Israeli Centers for Research Excellence; Funding details: RGPAS/477902-2015, NSERC, Natural Sciences and Engineering Research Council of Canada; Funding details: 244615/E30, Norges Forskningsråd; Funding details: 244615/E30; Funding details: 262644, CERC, Canada Excellence Research Chairs, Government of Canada; Funding details: NSERC, Natural Sciences and Engineering Research Council of Canada

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.

Pressure retarded osmosis (PRO) is one feasible technology that can be used to exploit the mixing energy from salt gradients which is commonly referred to as salinity gradient power or osmotic power. This paper focuses on the construction of iso-watt diagrams and their application for detailed evaluation of specific power in PRO on basis of membrane characteristics and site specific design parameters. Iso-watt diagrams are demonstrated to be a useful tool for investigation of the effect of variation in the membrane parameters, i.e. the water permeability, the salt permeability and the structure parameter, and how mutual changes in the characteristic parameters will impact the PRO performance. Thus, iso-watt diagrams can be considered an effective aid for goal-oriented membrane development. In addition, iso-watt diagrams can be considered to be useful also with respect to design related aspects, such as e.g. site selection. Further, membrane performance data are reported in the literature for various experimental conditions, which makes direct comparison difficult. The use of iso-watt diagrams enables an efficient way of presenting and comparing the efficiency of different membranes. This is demonstrated in the current paper for ten states of the art membranes.

Storage of CO 2 in deep saline formations is currently the most promising option for mitigating the impact of climatic changes. Therefore, it is important to understand flow processes and distribution of forces acting on injected CO 2 . To demonstrate the influence of gravitational, viscous, and capillary forces on the flow of CO 2 , special experiments were designed. Laboratory experiments and numerical simulations were performed, where fluid representing CO 2 was injected into a 2D porous medium saturated with fluid representing brine. Two sets of fluids characterised by different interfacial tension (IFT) were tested. Results demonstrate that at increasing injection rate viscous forces become stronger, leading to a higher total displacement of brine. Such performance is preferred at field scale, since it facilitates dissolution and residual trapping of CO 2 . Gravity effects were more pronounced in cases with low injection rates and high permeability and are demonstrated by lower volumes of the in-situ fluid displacement. Therefore, reservoirs giving low influence of gravity forces are more suitable for CO 2 storage. The high-IFT fluid system had an IFT corresponding to the value of CO 2 –brine systems at possible reservoir conditions. However, the fluid flow in the laboratory model was dominated by capillary forces. This kind of behaviour is less likely to be observed at field scale as it is a result of the much smaller volume of porous system used in the laboratory compared to the volume at the field scale. The low-IFT fluid system resembled better field scale flow behaviour. The laboratory experiments were also modelled using a numerical reservoir simulation software. While modelling of observations from high-IFT system was challenging, simulations for low-IFT displacements showed accurate reflection of experiments.

Pressure retarded osmosis (PRO) can be used to exploit the mixing energy e.g. between river water and sea water. A PRO membrane must be highly permeable for water, whereas salt ions should be retained. Furthermore, the structure parameter of the membrane support and backing structure must be low. This paper summarises an assessment of the pressure dependency of the structure parameter for flat sheet membranes, and a transport model for PRO and procedures for determination of the pressure dependency of the structure parameter are presented. The results from laboratory experiments show that that the structure parameter increases significantly with increasing trans-membrane pressure. The increase in the structure parameter was observed to depend on both characteristics of the membrane and the fresh water spacer. Using a finely textured tricot spacer reduced the pressure dependency on the structure parameter, compared to a coarser spacer. Applying a non-woven backing material between the membrane and the fresh water spacer also reduced the impact of pressure. The results show that membranes suitable for river water/sea water PRO must have a sufficiently low structure parameter and additionally resist severe deformation at relevant operating pressures.

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.