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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.

Osmotic power extracted from the mixing of freshwater with seawater is a renewable energy resource that has gained increasing attention during recent years. The estimated energy can significantly contribute to the production of power worldwide. However, this power production will be subject to variation due to both local conditions and seasonal variation. The present paper explores the effect of concentration and temperature on water and salt fluxes in osmosis at zero transmembrane pressure for five different membranes. Further, the measured fluxes have been utilized to model water and salt permeabilities (A and B), and the structure parameter (S). The observed flux variations at different combinations of concentration and temperature have been ascribed to skin properties, i.e., changes in A and B of each membrane, whereas S was assumed constant within the range of concentrations and temperatures that were tested. Simplified equations for the variation in A and B with temperature and concentration have been developed, which enable A and B to be calculated at any concentration and temperature based on permeabilities determined from osmotic experiments at standard test conditions. The equations can be used to predict fluxes and specific power production with respect to geographical and seasonal variations in concentration and temperature for river water/seawater pressure-retarded osmosis. The obtained results are also useful for forward osmosis processes using seawater as draw solution.

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.

Injection of alkaline water can potentially yield large amounts of calcium naphthenates in the reservoir. This can cause a problem if the precipitate moves through the reservoir and accumulates in the near well bore or the production system. The objective of this work was therefore to investigate whether calcium naphthenate would propagate through a porous medium. Highly permeable (∼1 darcy) water-wet Berea sandstone was used as porous medium with toluene as the model hydrocarbon phase. A special type of naphthenic acid (ARN) was added to the toluene phase. Aqueous and toluene phases were injected at a 50/50 volume ratio with a total interstitial velocity close to 1 m/day. Three vertical core flooding experiments were performed at 85 °C. The produced fluids were analyzed for ARN. After flooding, the cores were cut in sections, crushed, and extracted with toluene under acidic conditions to yield ARN profiles.

Fouling is one of the major challenges to be solved in order to commercialise osmotic power generation by pressure retarded osmosis (PRO). This paper deals with natural organic matter (NOM) fouling. The impact of i.a. NOM concentration and ionic strength in the freshwater feed have been investigated for five different types of PRO membranes by performing fouling experiments in PRO mode at isobaric conditions. An important finding was that fouling propensity in terms of relative flux decline as a function of accumulated NOM load was independent of the NOM concentration at otherwise identical conditions. Further, it was confirmed that increased ionic strength in the support structure, due to internal concentration polarisation and reverse salt diffusion, aggravates membrane fouling in PRO. The observed variation in fouling propensity between different types of PRO membranes was significant. The CA membrane was less susceptible to NOM fouling than the four TFC types of PRO membranes. It is anticipated that the variation in fouling propensity that were observed for different membranes was related to both material and structural properties of the membranes. The results show the importance of applying fouling propensity as an additional main criterion to membrane performance during future research and development of PRO membranes.

The principle of pressure retarded osmosis is to utilize parts of the free energy of mixing of solutions with different salinities for production of mechanical energy. The mixing process takes place over a semi-permeable membrane as water is transported from the less concentrated salt solution to the more concentrated salt solution due to difference in chemical potential of water. The PRO process will be operated with elevated pressure on the side of the membrane having the highest salt concentration, corresponding to approximately half the difference in osmotic pressures for the two solutions. The net increase in volume on the pressurised side can be utilized to run a turbine. This paper has focused on modelling the power production and pressure drop in hollow fibre modules with different flow configurations, i.e. co-current and counter current longitudinal flows and elements with longitudinal flow inside the fibres and radial flow in the shell. The overall PRO performance is similar for the different flow configurations. The radial flow configuration has a superior pressure drop in the shell side compared to the longitudinal flow configurations, but the total membrane area for a given element size will be larger for the longitudinal flow configurations.

The principle of PRO is to utilise parts of the free energy of mixing when mixing freshwater with seawater for production of electrical energy. The mixing process takes place over a semi permeable membrane that will retain salts, and ideally allow only transport of water. The transport of water will occur due to differences in chemical potential across the membrane. The PRO process will be operated with elevated pressure on the seawater side of the membrane, and the net increase in volume due to osmotic transport of water across the membrane, can be utilised to run a turbine and hence produce energy. At present the biggest challenge in PRO is to develop membranes with sufficient specific power. This challenge involves optimisation of the basic membrane characteristics, i.e., high water permeability (A), low salt permeability (B) and low structure parameter (S). In this paper a transport model for water and salt in hollow fibres in PRO has been developed. Further, a structure parameter equivalent to the structure parameter for flat sheet membranes has been defined. The impact of the membrane parameters (A, B and S) on PRO performance in a hollow fibre element has been demonstrated by applying iso-watt diagrams. In general, for a given structure parameter S, increasing the A value and decreasing the B value will increase the specific power. It was also found that if the salt permeability exceeds a certain level, a further increase in the water permeability will not result in a corresponding increase in the specific power. Similarly, if the water permeability is lower than a certain level the effect of increased salt permeability will be low. Further, the PRO performance of different hollow fibre membranes has been estimated using the iso-watt diagrams. Based upon the reported membrane characteristics the PRO performance for the selected membranes ranges from less than 1 W/m2 to above 4.5 W/m2. The membranes having a specific power around 4.5 W/m2 are promising candidates for future PRO plants, given that these membranes can tolerate the typical operation pressure in a PRO plant of 12–14 bar.

Summary Low-salinity (lowsal) waterflooding has been evaluated for increased oil recovery (IOR) at the Snorre field. Coreflooding experiments and a single-well chemical tracer-test (SWCTT) field pilot have been performed to measure the remaining oil saturation after seawaterflooding and after lowsal flooding. The laboratory coreflooding experiments conducted at reservoir and low-pressure conditions involved core material from the Upper and Lower Statfjord and Lunde formations. The core material from the Statfjord formations gave incremental recovery in the order of 2% of original oil in place (OOIP) by injection of diluted seawater. Similar amounts were produced during following NaCl-based lowsal injections. The same trend was observed in the high- and low-pressure experiments. No significant response to lowsal flooding was observed for Lunde cores. No response was normally observed during alkaline injection. The SWCTT field pilot was carried out in the Upper Statfjord formation. The average oil saturations after seawater injection, after lowsal seawater injection, and after a new seawater injection were determined; no significant change in the remaining oil saturation was shown. The measured in-situ value of remaining oil saturation after seawaterflooding was in agreement with previous special core analysis (SCAL) experiments. The measured effect of tertiary lowsal flooding from core experiments was in agreement with the SWCTT. Both measurements indicated only low or no effect from lowsal injection. It has been suggested that lowsal flooding has a potential for improved oil recovery in all clayey sandstone formations containing crude oil. The results from this work indicate that the initial wetting condition is a crucial property for the effect of lowsal injection.

A large amount of potential renewable energy can be extracted from the mixing of freshwater and seawater. Two membrane processes can be used to extract this energy, namely pressure retarded osmosis (PRO) and reverse electrodialysis. Both processes need membranes that are similar to the ones used to perform reverse osmosis and electrodialysis. So far neither of the processes has been optimally designed. In the present study PRO has been analysed for potential power production. It appears that PRO exhibits a significant potential for power production and future developments may further improve this. A specific power in the order of 5 W/m2 of membrane seems possible and approximately 40 per cent of the potential mixing energy of freshwater with infinite amount of seawater can be converted to mechanical energy. This article aims to describe the PRO process and to develop guidelines for the development of membranes that are suitable for PRO. Furthermore, some experimental results from laboratory measurements are included both to verify the model and to show present state of membrane development.

The idea to generate power through osmosis between river and ocean water has been known since the 1970s. The potential power that can be produced worldwide through osmotic power is estimated to be 1600 TWh/a. But due to inefficient membranes, little effort has been put into research for this type of renewable ocean energy. In 2001, Statkraft, one of the major energy providers in Norway, invited GKSS-Forschungszentrum to develop a suitable osmosis membrane for pressure-retarded osmosis (PRO). Two different types of membranes were optimised: thinfilm composites (TFC) and asymmetric cellulose acetate. To make PRO profitable, the power density of the membrane was determined to be between 4–6 W/m2. Starting with power production from 0.1 W/m2 for the TFC membrane, a power density of 3.5 W/m2 with a potential of 5 W/m2 was measured. The starting value for the CA-type was approximately 0.5 W/m2, and the best measured performance was 1.3 W/m2. However, if it is possible to improve PRO membranes further, PRO will move to the idea of a profitable application, generating green, emission-free energy.

In the North Sea tilted oil–water contacts (OWCs) are recognized in fields of Paleocene, Cretaceous and Jurassic age. In areas where lateral pressure (potentiometric) gradients exist in the aquifer, OWCs dip in the direction of pressure drop and hydrodynamic flow occurs. The direction and magnitude of potentiometric gradients in the North Sea vary locally, but are generally observed to be associated with de-watering of the overpressured Central Graben. Local variations in the potentiometric gradient can be caused by heterogeneity in the aquifer, such as faults, channels, facies changes, pinchouts and/or thinning. These variations cause local irregularities in a field’s tilted OWC. Where an aquifer beneath a field becomes less permeable or thins, the dip of the OWC increases. Where the aquifer becomes more permeable or thickens, then the tilted OWC tends to flatten out. Channels and high-permeability zones tend to concentrate aquifer flow and direct the potentiometric gradient along their axes. Various combinations of aquifer heterogeneity have been modelled in 3D simulations. These models are described and compared with real examples from North Sea fields.

Wettability tests were performed using Berea sandstone, NaCl brine, and n-decane with different concentrations of hexadecylamine. The tests were performed on cores both with and without initial water. Adsorption tests of the additive have also been performed on crushed Berea sandstone. It was shown that it is possible to modify the wetting properties from water-wet to neutral by the addition of a small amount of hexadecylamine. This is most likely due to adsorption of the additive on the rock surface. The resulting wetting properties were observed to be dependent on the concentration of the additive, and the effect of the additive is higher for cores not having any initial water. It was also observed that both residual oil saturation and irreducible water saturation decrease when the cores approach neutral wetting properties. This could be due to the formation of two continuous phases through the cores and less capillary trapping. The adsorption results show an increasing adsorption with increasing concentration, and the amount of adsorption for dry sandstone is twice the amount of initially water-saturated sandstone.

Wettability tests have been performed using two different North Sea sandstones and three different fluid systems composed of a NaCl-brine and pure n -decane, or n -decane with additives. Oil displacement experiments by water injection with composite cores of the same types of sandstone, and the same fluid systems, have also been done. It has been shown that it is possible to modify the wettability characteristics of the two sandstones from water-wet to neutral-wet, and further to oil-wet, by addition of small amounts of organic acid or organic base to the oil. Wettability indices obtained by the Amott and USBM tests are consistent. Water injection into two composite sandstone cores with fluid systems giving the three different states of wettability mentioned above, responded as expected. The water-wet cores had the highest oil recoveries at water break through. The non-water-wet systems all exhibited a significant tail production of oil. The highest ultimate oil recoveries were obtained for the neutral-wet systems, and the lowest recoveries were given by the oil-wet systems. Change in wettability by addition of organic acids or bases to the oil is likely to be due to adsorption of the additive on the surface of the rock. The mechanism of wettability alteration is thus similar to what can be obtained by the addition of a water-soluble surfactant to the brine. The only difference is that an additional interphase mass transfer step is involved for the oil-soluble, practically water-insoluble, additive to reach the rock surface by diffusion.

SummaryFoam propagation in co-injection of gas and surfactant solution has been studied in a 10-m-long flow apparatus, equipped with pressure ports and fluid sampling valves for every 1 m. The data have been compared to the results of a core scale foam flooding experiment with the same porous medium.The propagation experiments on the 10 m scale revealed that the foam front propagated significantly slower than the injected fluid front. It appeared that foam propagation was not limited by surfactant transport, but was delayed due to the presence of oil in the porous medium. The experiments have been interpreted with the aid of a numerical foam simulator.

The objective of this study was to determine the influence of surfactant concentration, surfactant adsorption and interfacial tension between oil and aqueous phase on the Amott wettability index and the residual oil saturation during waterflooding. The flooding experiment and Amott wettability tests were performed on 60 core plugs at a temperature of 50°C, with n-heptan and 1.5 wt.% NaCl brine with 12 different concentrations of surfactant. The anionic surfactant used in the experiments was n-dodecyl-o-xylene-sulfonate with a well-known interfacial tension vs. concentration relationship. The core material was Berea Sandstone with an average porosity of 19% and an average permeability of 104 md. Wettability indexes were determined by the standard Amott test involving spontaneous uptake of fluids and forced displacement steps. The Amott wettability index and residual oil saturation vs. surfactant concentration and an adsorption isotherm of the surfactant on Berea sandstone were the main quantities determined. The results show that increased surfactant concentration results in a change in wettability from strongly water wet to weakly oil wet. The residual oil saturation decreases with increasing surfactant concentration. A dramatic change in wettability from water wet to neutral and over to oil wet occurs in a narrow range of low concentrations which coincide with the critical micelle concentration. In this range the measured adsorption was only approximately 10% of the maximum value of the adsorption isotherm. Higher surfactant adsorption at higher concentrations did not have significant effect on the observed wettability.

A pre-study of a concept for power production offshore on abandoned platforms shows that a net delivered 300 MWe combined cycle power plant and a CO2 sequestering plant can be located on a single Condeep platform. By replacing the present gas turbine power production on neighbouring oil fields, the CO2 emissions will be reduced by 1.6 Mt per year, corresponding to 4.4% of the total Norwegian emissions. The concept appears to be both technically and economically feasible.

A study of CO2 injection into an oil reservoir on the Norwegian Continental Shelf has been conducted. With a numerical reservoir simulator a production profile from a scenario where the reservoir pressure is maintained by displacing oil with CO2 has been performed on a three dimensional reservoir model using reservoir properties measured in the laboratory. The forecasted production profile was compared to the profile that was obtained when CO2 was substituted by water. The simulations showed that considerably more oil could be recovered with CO2 injection, approximately 60% of original oil in place, compared to approximately 40% by water injection. A technical/economical evaluation of CO2 separation from industrial sources, transport and injection into oil reservoirs has also been made. The results show positive economics only when some sort of CO2 tax avoidance is imposed on the source which alternatively would release CO2 into the atmosphere.

Low salinity water (lowsal) flooding has been evaluated for increased oil recovery at the Snorre field. Core flooding experiments and a single well chemical tracer test (SWCTT) field pilot have been performed to measure the remaining oil saturation after sea water and after lowsal flooding.The laboratory core flooding experiments done at reservoir and low pressure conditions involved core material from the Upper and Lower Statfjord and Lunde formations. The core material from the Statfjord formations gave incremental recovery in the order of 2 % of original oil in place (OOIP) by injection of diluted sea water. Similar amounts were produced during following NaCl-based lowsal injections. The same trend was observed in the high and low pressure experiments. No significant response to lowsal flooding was observed for Lunde cores. No response was normally observed during alkaline injection.The SWCTT field pilot test was carried out in the Upper Statfjord formation. The average oil saturations after sea water injection, after lowsal injection and after a new sea water injection were determined; showing no significant change in the remaining oil saturation. The measured in-situ value of remaining oil saturation after sea water flooding was in agreement with previous SCAL experiments.The measured effect of tertiary lowsal flooding from core experiments was in agreement with the SWCTT. Both measurements indicated only low or no effect from lowsal injection.It has been suggested that lowsal flooding has a potential for improved oil recovery in all clayey sandstone formations containing crude oil. The results from this work indicate that the initial wetting condition is a crucial property for the effect of lowsal injection.

The efficiency of tertiary CO2 injection at the reservoir conditions into fractured cores has been investigated experimentally. The experiment was designed to illustrate the process of water imbibition and CO2 injection into a North Sea chalk reservoir. The core and core holder assembly were designed to allow a 2 mm gap to surround the core simulating a fracture. Live reservoir oil was prepared and used to saturate the matrix system. Due to the large permeability contrast between the core (4 mD) and the fracture it is not feasible to saturate the core by simply flooding the system with live oil, since oil would flow through the fracture and only partially saturate the core. To overcome this problem a unique technique has been developed for saturating the matrix system with reservoir fluids. This method ensures a homogeneous fluid composition within the pore system before the fracture system is initialized by the injection fluids (water/CO2). During the experiment, the matrix system was first saturated with the live reservoir oil, during which the gap was blocked by a sealing material. In the next step the sealing material was removed and water was injected into the gap. Finally CO2 was injected at a low and constant rate into the gap. Oil and water production and fluid composition were monitored and the results show that injection of CO2 could significantly recover residual oil after water injection.

Publisher Summary This chapter illustrates an injection scenario that includes most of the Norwegian oil reservoirs in the North Sea oil reservoir. In order to elucidate the possibility of combining CO 2 storage with EOR, a techno-economic model for a large scale scheme for CO 2 deposition in Norway's North Sea oil provinces has been developed. A CO 2 -transportation module calculates the transportation costs for CO 2 from export terminals to the oil provinces. An EOR module predicts the increased oil recovery due to CO 2 injection in water-flooded reservoirs. In order to convert from a water-injection scheme to CO 2 injection large modifications of the oil production installations are needed. A possible solution for this has been sketched, and the costs for the necessary modifications and new installations for CO 2 injection have been estimated and are also included into the techno-economic model.

The costs incurred in processing and disposal plus environmental concerns to minimise discharges during oil production have always created a desire to control unwanted fluid phases. In this paper, the potential of stopping the production of water by use of oil-wet selective membranes that allow oil flow and shuts off water has been studied. Water is an issue in the oil industry because it is a prime field abandonment criterion leaving trapped hydrocarbons behind. The implementation of the membrane technology was verified through numerical simulations of different reservoir geometries. The simulations were performed on models where the water was either retained in the reservoir or where a water removal system was involved. During the simulations, the selective membrane was placed either on the production tubing or towards the reservoir rock wall. Production profiles for the membrane wells have been compared to the production from conventional (base case) wells without the membrane. The results have shown that completing a production well with an oil-wet membrane shuts off water production as long as the water capillary entry pressure of the membrane is not exceeded. It was observed that the water block that accumulates in the annulus and near the well-bore area after water arrival at the well reduces the oil contact with the membrane and hence the flow of oil to the production tubing. The simulation models other than the base cases have illustrated that the membrane well can act as a downhole separator. It was further observed that by optimising the design of removing the accumulated water from the annulus and proper timing to open the water removal facilities, it is possible to produce "water-free" oil at a total recovery efficiency as high as in conventional wells or better.

Foam propagation in co-injection was studied in a 10 m long porous medium, equipped with pressure ports for every 1 m. The porous medium had been characterized by flooding experiments on the core scale. In the absence of oil, propagation on the 10 m scale could be understood by corescale, steady-state foam properties. In the presence of oil, however, the foam front propagated significantly slower than the injected fluid front. An extraction mechanism for oil combined with foam oil sensitivity can explain the delayed propagation. These effects were included in a foam simulator that reproduced the slow foam propagation.

The position of the oil-water contact (OWC) in a prospect or field is one of the most important factors in determining reserves. In the central North Sea, OWCs in the Cretaceous Chalk Group and in Paleocene sandstones can be naturally tilted by bed-parallel hydrodynamic activity as the Central Graben dewaters. Examples of fields with interpreted tilted OWCs are described, and set within their regional hydrodynamic context. In addition, laboratory experiments and computer simulations are used to examine the response of fluid contacts to aquifer heterogeneity in a hydrodynamic environment. These models can be used predictively, improving the understanding of tilted OWCs in fields, helping to explain dry wells and to improve planning and risk analysis for both exploration and development drilling.

Abstract The spreading characteristics of a gas/oil/surfactant solution system depend on the interfacial tensions involved. This work indicates that systems having interfacial tensions giving spreading oil act more deleterious to foam stability as compared to nonspreading oil systems. The effect was demonstrated for Berea sandstone by changing the oil when the type of surfactant was unaltered and by changing the type of surfactant when the oil used was the same. For a slightly oil-wet reservoir rock a similar trend in foam properties was observed when the type of oil was changed. In an oil spreading system the flow resistance of foam was found to increase with increasing concentration of the surfactant solution. Introduction The concept of using foam to reduce gas mobility was initially patented by Bond and Holbrook in 1958. Foam may be utilised for different purposes in a reservoir situation, either for zone blockage or for mobility control of gas. The former needs a strong and viscous foam, whereas the latter requires a less rigid foam. Several successful foam injection projects have been performed. The purpose has mainly been gas diversion and blocking of high permeable streaks. However, minor experience exists on the use of foam for mobility control, a situation where foam has to propagate throughout the whole reservoir. Influence of Oil on Foam Stability The presence of oil in porous media is generally known to decrease the mobility reduction of gas obtained by foam. This has obviously implications for the use of foam in improved oil recovery. Several mechanisms have been suggested in order to explain the effect of oil on foam properties. Much attention has been paid to effects related to the surface energies involved in the gas/oil/surfactant solution system. Lau and O'Briens and Kuhlman have indicated that spreading of oil on foam bubbles or lamellas decreases the stability of foam. Oil spreading may cause film thinning below a critical limit for mechanical stability, and the lamella breaks. Manlowe and Radke, however, have suggested that spreading of oil on foam lamella is not critical. Rather, the so-called "pseudoemulsion-film" governs the foam stability. This film is formed whenever foam bubbles or lamellas contact oil. Schramm et al. bring the lamella number, L, and the entering coefficient, E, into a phenomenological theory for the effect of oil. If L is greater than one, small oil droplets will be sucked into the Plateau borders of foam lamellas due to the low hydrostatic pressure in this region. If E is greater than zero, the oil droplet will enter the lamella surface. If, further, the spreading coefficient for the oil, S, is positive, the oil will spread over the surfactant solution surface. This may lead to lamella rupture. If both E and S are negative, oil will neither enter the lamella/gas interface or spread over it. This is the situation where the presence of oil is believed to have the least deleterious effect on foam stability. P. 279^

In studies of bi-ionic cells containing strontium and potassium chlorides separated by a cation exchange membrane, the water transference was found to have a non linear dependence on ion transference numbers. This finding suggested the existence of local pressure gradients within the membrane during irreversible flow. In order to evaluate this possibility, we developed a method to obtain the concentration profile in a cation exchange membrane from measured fluxes. This permits the calculation of local transport coefficients for the coupled transport of mass and charge by two salts and water within the membrane. The observed variations in transport coefficients across the membrane are used to calculate the hydrostatic pressure profile inside the membrane. The results show that the postulated pressure gradient does exist, but that it has a negligible effect on the chemical potentials. This means that cell potentials can be calculated using the concentration dependent terms of the change in Gibbs free energy.

Local transport coefficients have been experimentally determined for transport of H+, Na+, H2O and current, and for transport of K+, Sr2+, H2O and current in a cation exchange membrane. Adjacent electrolytes contained 0.03 N solution mixtures of HCl and NaCl, or 0.03 N or 0.01 N solution mixtures of KCl and SrCl2. The fluxes and forces used in the presentation are based on a choice of neutral and independent components of the system. — The concentration dependence of the membrane conductivity and the electric mobility of ions has been described by a model which relates the reduction of one cation mobility to the equivalent fraction of the other cation. The mobility ratio varies between 4 and 15 for uH+/uNa+ and 3 and 6 for uk+/uSr2+. The transference numbers for the monovalent salt system can be predicted within experimental uncertainty limits from this model. Local diffusion coefficients are derived and compared to electric mobilities. The result is that the Nernst-Planck equation using equal electric and diffusional mobility is valid for all concentrations within ± 10% on the average for both systems. Water transport will modify the Nernst-Planck flux equations when gradients in chemical potential of water becomes about 10−5 times the gradients in chemical potential of salts. Calculations predict a negligible contribution to the chemical potential gradient of salts from pressure variations in the membrane during interdiffusion. — In total these results make possible a continuous description of membrane transport processes.