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The effect of pressure and rock type on optimal dual energy levels and minimalisation of saturation uncertainties for threephase core experiments was investigated. X-ray scanning of a composite core comprising of two chalk plugs and one Berea sandstone core was done. Reference scans using CO2, natural seawater, n-CO[10] and aCO2/n-C[10] mixture at four pressure stages and five different pre-defined dual energy levels were acquired. Two unique typical given saturations were input together with data from the reference scans in a routine for back-calculating three-phase intensity data. A detailed uncertainty analysis using these synthetic three-phase data and combining low and high energies was performed. The resulting combination of low and high energy level giving the lowest uncertainty was selected as a given setting for all dynamic scans. Saturated with live oil, the core was waterflooded while dynamic X-ray scans were acquired. After the waterflood, the core was depleted below the bubble point to atmospheric pressure while scans were acquired continuously. The results show that the rock type largely effects the selection of energy levels for both two- and three-phase X-ray scans. To minimise the uncertainty, the chalks generally required a higher low energy level independent of pressure than the sandstone. Also, at high pressures and for all rocks the optimal high energy level was found in the same range. At lower pressures, a lower high energy level was favourable. Introduction After X-ray computerised tomography (CT) was introduced to medical radiology, X-ray measurements of rock material has gradually become an important tool within many branches of petroleum engineering.[1–6] Today, many of the worlds reservoirs are declining, and the need for accurately assessing a reservoir is therefore even more important than before.[7] Despite this, for laboratory work reported in the petroleum literature, measurement uncertainties are often neglected.[8] Independent of technique, measurements of saturations inside rock are in practise associated with considerable uncertainties. Identifying and quantifying uncertainties are valuable when interpretingand applying laboratory data to a field production scenario. Adding this information can contribute to improved reservoir assessment, economical analysis and, thus, improved oil recovery. In practise, to calculate three-phase saturations from X-ray scanning of rock material, at least one of the liquid fluids are doped, i.e. a chemical that increases the density of the fluid substantially is added.[9] Altering the density will also alter the fluid viscosity and the interfacial tension between fluids.[10] Thus, important fluid/rock interactions will be described unrealistically. In future, one should preferably conduct experiments using reservoir fluids, even when the saturation calculation is based on in-situ measurements of attenuation of a photon beam. To achieve this goal, the need for a well-designed experimental setup is decisive. Although it should be of interest to the experimental reservoir engineer, guidelines for selecting appropriate dual energy levels for rock scanning are, to our knowledge, not established.[11] However, from any experimental setup to the next there exist substantial differences: Carbonate rock is composed of different species than sandstone, heavy oil consist of bigger molecules than simple hydrocarbons not to mention that one coreholder will scatter radiation more or less than others. Appropriate energy levels are not trivial to find and we assume them to be dependent on the particular set of fluid, rock and experimental apparatus used. This paper provides a scope for designing saturation measurements in terms of finding suitable dual energies for different rock type at different saturations and pressures, by using an X-ray scanner.

The gas cap contamination level and mechanisms caused by CO2-EOR operations in an oil field have been investigated by compositional reservoir simulations on a sector model of the Upper Tilje reservoir. The impact of different EOR and gas cap drawdown operational parameters on the contaminated gas volumes has been determined. The results show that the contaminated part of the produced gas from the gas cap, with more than 2.5% CO2, can be correlated to the final position of the CO2 front during the EOR-period. Massive CO2-breakthrough on the other hand, which is responsible for the contaminated part of the produced gas with more than 7.5% CO2, is a nearly linear function of the stored CO2 mass. This implies that EOR-operations which both increase oil recovery and CO2 storage, such as SWAG-injection, short-cycle WAG or oil producer gas shut-off will significantly increase gas cap contamination. Gas cap contamination however can be reduced by well-positioned horizontal gas producers and large gas blowdown flow rates. Introduction CO2-EOR has been applied on large scale in the US since the seventies and is still the most important EOR-technique in the US until today. So far, an estimated volume of one billion barrels oil has been recovered by CO2-flooding and 206 GSm3 CO2 have been sequestrated 1. In those American fields, mainly in the Permian basin of Texas and New Mexico, the CO2 is available from natural CO2-reservoirs and anthropogenic sources and is transported by extensive pipeline systems to the different fields. This is in contrast to the situation in the North-Sea where the CO2 is not naturally available and offshore pipelines have to be built to make CO2-injection possible. Nevertheless, CO2-injection for EOR in the North Sea has gained new interest due to the expected climate effect of CO2 emissions on the atmosphere. The Norwegian government has established a CO2-emission tax of around $50 per ton and together with the current high oil price, CO2-EOR could become an economically profitable recovery method for the North-Sea region. As a result, Statoil ASA and Shell have started a joint evaluation of the EOR-potential by CO2-injection in the Heidrun and Draugen fields respectively. Between 2 and 2.5 Million tons of CO2 will be available per year from 2012 on and will be delivered by a planned onshore electricity plant at Tjeldbergodden which is about 200 kilometres south-east of both fields. One of the drawbacks of CO2-injection in the Heidrun-field is the contamination of the gas in the gas cap by CO2, which will reduce the commercial value of the gas and cause operational problems. In this paper we have investigated the impact of CO2-injection on the gas cap contamination by compositional reservoir simulation. The simulation study has been performed on a sector-model, containing the H and I segment of Upper Tilje which is the main reservoir of Heidrun that contains a commercial gas cap. Different EOR and gas cap drawdown scenarios have been simulated, and the CO2-contamination levels of the produced gas have been compared for the different cases. Preliminary full-field production profiles by CO2 for Heidrun are reported elsewhere 2. Field Description Heidrun is a major Norwegian oil and gas field, discovered in March 1985 in Block 6507/7 in the Norwegian sea, about 150 km north-west of Trondheim. The average water and reservoir depths are 350 and 2500 metres respectively, giving a hydrostatic reservoir pressure of 250 bar. Initially, the field contained a volume of 440 MSm3 of oil and a gas cap containing about half of the 90 GSm3 of hydrocarbon gas (HC-gas). The production started in October 1995 and today, the production is 20,000 Sm3/day of oil and 5.5 MSm3/day HC-gas. The production strategy has so far been waterflooding with re-injection of some of the produced gas in the gas cap for pressure maintenance. Current predictions give an economical oil production till 2030 with a tertiary gas cap production at the end of the field life. To increase the oil recovery, several IOR-methods are currently investigated for Heidrun, such as continuous well optimisation, polymer and surfactant flooding and CO2-WAG injection.