Torleif Holt

Hydrodynamic activity and tilted oil-water contacts in the North Sea

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.

An experimental study of the relationship between wettability and oil production characteristics

Abstract 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.

Tilted oil–water contacts: modelling the effects of aquifer heterogeneity

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 alterations due to an oil soluble additive

Abstract 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.

A large-scale infrastructure model for CO2 disposal and EOR—economic and capacity potential in the North Sea

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 Norways 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.

CO2 from industrial sources as injection gas in oil reservoirs

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.

Gas power with CO2 deposition located on abandoned platforms

Abstract 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.

Identification of Nanocellulose Retention Characteristics in Porous Media

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.

An Evaluation of Graphene Oxides as Possible Foam Stabilizing Agents for CO2 Based Enhanced Oil Recovery

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.

Concentration and Temperature Effects on Water and Salt Permeabilities in Osmosis and Implications in Pressure-Retarded Osmosis

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.