Petrographic composition, diagenesis and reservoir quality of the Upper Triassic fluvial to marginal marine Fruholmen Formation, the Middle and Upper Triassic estuarine and coastal plain Snadd Formation, and the Middle Triassic estuarine Kobbe Formation have been examined in wells 7131/4-1 and 7222/11-1 located on the western Bjarmeland Platform and on the eastern Finnmark Platform in the southern Barents Sea. Twenty-nine thin-sections from the Fruholmen Formation, sixty-eight from the Snadd Formation and eleven from the Kobbe Formation were studied with a petrographic microscope, forty were point-counted, and six were studied with a cathodoluminescence microscope. The petrographic observations were compared with plug measurements of porosity and permeability.The Fruholmen Formation sandstones are moderately well and well sorted fine-, medium- and coarse-grained quartz arenites. The Snadd Formation sandstones are moderately well and well sorted and fine- and medium-grained, and the Kobbe Formation sandstones are mostly well sorted and fine-grained. Both the Snadd and Kobbe Formations comprise sublitharenites and lithic arenites with common to abundant metasedimentary rock fragments, but the Snadd Formation contains both K-feldspar and plagioclase, whilst the Kobbe Formation contains plagioclase only. These compositional differences between the three formations may largely be a result of the Snadd and Kobbe formations having had an eastern source area (Uralides), and the Fruholmen Formation a more southerly source area (Scandinavia), although a shift to a more humid climate in the Late Triassic may also have influenced sand composition.The Fruholmen Formation sandstones contain very little diagenetic cement, typically 1-2% quartz overgrowths, traces of pyrite cement, and occasionally 1-2% authigenic kaolin. The main diagenetic cement in the Snadd Formation is early diagenetic chlorite that occurs as grain coatings and more rarely as pervasive microporous pore-filling cement. Siderite is present in most Snadd Formation samples in amounts of 1-6%, and a few thin zones are strongly calcite-cemented. Up to 3% authigenic kaolin is commonly present, and traces of pyrite cement and quartz overgrowths occur. The Kobbe Formation sandstones contain the same diagenetic minerals as the Snadd Formation, plus a few albitic overgrowths on plagioclase. However, the total volumes of diagenetic minerals in the Kobbe Formation are typically very low, 1-5% in the point-counted samples.Diagenetic chlorite or poorly crystalline chlorite precursors may have formed from iron-rich colloidal material brought in by rivers and flocculated where fluvial waters mixed with marine waters. These colloids may also have been the main source for iron in early diagenetic siderite. Partly dissolved biogenic carbonate is still present in the Snadd and Kobbe formations, and carbonate fossils are probably the source of the calcite cement. The calcite cement engulfs and therefore postdates chlorite grain coats, siderite cement and authigenic kaolin. Quartz overgrowths were sourced from dissolution of quartz grains at stylolites evolved from clay laminae when temperatures reached 70-80°C.Reservoir quality is largely excellent in the Fruholmen Formation sandstones (25-32% helium porosity, 1 000-38 000mD permeability) because contents of detrital clay and diagenetic minerals are almost zero. Snadd Formation porosities are also in most cases high to very high, 26-36%, partly due to the chlorite coatings inhibiting quartz cementation. Permeabilities are mostly 100 to 5 000mD, but where microporous diagenetic chlorite fills the pore system permeabilities are very low to low, 0.1-15mD. The Kobbe Formation sandstones have been more deeply buried than the overlying formations, approximately 3.5km, content of soft components (detrital and authigenic clay, mica-rich rock fragments) is high, and compaction has therefore been severe. Porosities are consequently quite low, 15-21%, even in the best of the cored Kobbe Formation sandstones, and together with the fine grain size this results in low permeabillities, 1-20mD.Burial depth for the shallowest examined cores is only 0.4 and 0.56km, and present temperatures are around 30°C. The consolidated nature of these cores and the presence of quartz overgrowths that normally start forming at 70-80°C therefore suggest that the sandstones have been more deeply buried than at present. Lack of illitization of kaolin in the deepest samples indicates that they have not been subjected to temperatures above 130°C. Together with the degree of quartz cementation in the various examined samples this suggests uplift of around 1.5km in well 7131/4-1 and 1.7km in well 7222/11-1. Comparison of the present porosities in the quartz arenites of the Fruholmen Formation with the porosity depth trend for the Garn Formation also suggests 1.5km of uplift in well 7131/4-1.

AbstractUnderbalanced drilling has received more and more attention in recent years. The reason for that may be because many oil fields, especially on the Norwegian continental shelf, have started to show signs of aging. By that I mean that the production is going down, and reservoir pressure is more and more reduced. Underbalanced drilling is a technique that is suitable for dealing with these challenges. The major benefits like for example reduced reservoir damage, and the ability to drill through narrow pressure windows, both help in prolonging the life of mature fields. To be able to perform a successful underbalanced drilling operation control over the pressure in the well is crucial. The bottom hole pressure must be controlled and adjusted as the operation goes on to make sure that underbalanced conditions are maintained at all times. My main goal with this thesis have been to demonstrate how the bottom hole pressure can be controlled by different parameters, and the investigation of different scenarios that can occur during an underbalanced operation and how they affect the bottom hole pressure.The Drillbench package contains two multiphase flow simulators that are specialized for underbalanced drilling. The Steadyflodrill is a steady-state simulator and the Dynaflodrill is a dynamic simulator. The dominant simulator in my work has been the Dynaflodrill.During drilling the bottom hole pressure is adjusted and controlled with three different parameters. These are the liquid injection rate, gas injection rate and the choke opening. Which of these parameters that will change the bottom hole pressure the fastest will vary with the type of well being drilled. Doing a connection during underbalanced drilling can be problematic, but this will vary with the type of reservoir being drilled. Separation of fluids in the wellbore when circulation is halted can cause severe fluctuations in the bottom hole pressure. By using the choke these fluctuations can be reduced to an acceptable level. Tripping underbalanced also offer challenges regarding separation of fluids which will kill the well after some time since the circulation is stopped for a long period. Also reservoirs containing heavier oil will be killed eventually if the reservoir is under pressured. Drilling through narrow pressure windows can be problematic if a pump failure should occur. This failure can lead to a sudden drop in the bottom hole pressure which can cause it to drop under the collapse pressure limit of the formation and cause for instance a stuck-pipe situation. Hitting an unexpected high pressure zone can lead to a well control situation due to an increased influx of formation fluids which exceeds the limits of the separator.Automation of underbalanced drilling has been difficult due to low data transportation rate from the bottom to surface, and difficulties with correct modeling of the multiphase flow in the well. A possibility can be to make use of the pump pressure and make an estimation of the bottom hole pressure based on that and a model of the friction in the drill pipes.

The oil industry has been exploring and drilling for hydrocarbons for decades, and on the Norwegian Continental Shelf (NCS), most of the previously discovered big fields are in their ending phase. The remaining reserves in these fields may require highly complex wells, such as high pressure high temperature (HPHT) wells, and have not been previously drilled due to operational challenges in such a tight drilling window. Precise estimation of this window is therefore crucial when planning and drilling wells, something that may be done by the means of a carefully calibrated geomechanical model, describing the pressure gradients present in the formation of interest.This thesis involves building a 2D Tor field specific linear elastic geomechanical model, and describes the work process in order to do so. The 2D aspect of the model is due to the fact that several offset wells were utilized in the process of building the model, in the case of using only one well, the model would be 1D. By using log data, survey data and MWD data to build the initial model in the Predict software, operational observations found in daily drilling reports and suchlike documentation are then used to calibrate the model to coincide with these physical observations. This calibration is a crucial part of the modeling, as it will fine-tune the pressure gradients, resulting in the possibility of drilling a well that was previously thought to be close to impossible. When planning future wells in this area, compressing and decompressing the model to fit the formation depths of the planned well will allow an estimation of the safe drilling window. The initial accuracy is presumed to be high, however the more wells that are added to the model will increase the precision of it and lead to a better model.Based on the drilling window produced by the model, the casing structure and the mud design for the planned well can be estimated. Thus, on the basis of this model, with well estimated and reliable pore pressure gradients, fracture pressure gradients and shear failure pressure gradients, wells can be drilled both safely and cost efficient, allowing an optimal hydrocarbon recovery to surface.

Proper correlation between formation mechanical properties and acoustic data is essential for acquiring field rock mechanical data for analysis, and it has thereby a great significance to oilfield development.This thesis presents results from a correlation study between formation mechanical properties and acoustic wave velocities from a set of unpublished rock mechanical experiments on sandstone samples from the Norwegian shelf. The core samples from the Norwegian shelf were subjected to triaxial compression tests performed at various confining pressures with simultaneous measurements of acoustic velocities. Correlations between formation compressive strength, elastic stiffness and Poisson's ratio and compressional and shear transit time have been established.The results obtained in this study confirm that the stress level and the stress configuration affect the acoustic velocities, and this should be accounted for when using generalized empirical correlations to estimate formation strength, elastic stiffness and Poisson's ratio from acoustic logs in field studies. The empirical correlations established through this work are found to match reasonable well with other published relations. By acoustic logs from field studies, it is found that the empirical correlations overestimate the formation strength and the elastic stiffness.

Wettability is one of the most important parameters governing the rate of oil recovery from a porous medium. This thesis is a study of the wettability variations within the Frøy field in the North Sea, and its effect on the oil recovery. Several reports regarding the wettability and relative permeability of the Frøy field are available, and the conclusions from these reports are presented. The overall conclusion is that Frøy is on the oil-wet side of the wettability scale, with measured Amott-Harvey wettability indices ranging from -0.00189 to -0.73. An attempt was made to find wettability trends, relating the wettability index to variables such as distance above the water-oil contact, geological facies, permeability, the core’s staining level and so on, based on the measured data. Unfortunately, no such trend was identified.Only nine wettability measurements were available from the Frøy field while writing this thesis. This thesis concludes that in order to get a good statistical data set that can be used for establishing wettability trends, several wettability tests should be performed on cores sampled from a variety of distances above the water-oil contact, with different permeabilities and color staining levels, representing different rock types. And it is important to make sure that the cores have their original (native) wettability during the tests.More than 50 simulation cases have been made and run during the work on this thesis, testing the effect of wettability variations on Frøy, using the Schlumberger reservoir simulation program Eclipse 100. Wettability variations are simulated by assigning different relative permeability curves to different saturation function regions in the reservoir. For this reason, five sets of relative permeability curves were made, that represents wettabilities ranging from slightly water-wet to oil-wet, and different combinations of these curves were used in the simulation cases. There are many uncertainties in the given data and there are different ways of initializing the simulation model which may affect the simulation results. These issues are discussed in a separate chapter of the thesis.The simulation results showed that when the reservoir rock went from water-wet to oil-wet, the oil production went down, the water production went up, the water breakthrough occurred earlier and the oil recovery factor went down. The different producing wells were not equally affected by changes in the wettability.Two important conclusions were drawn from the simulation results. Firstly, it is difficult to estimate the effect of wettability variations on the production profiles if not the aquifer support and the fault transmissibility factors are modeled correctly, since these parameters also affect the production. And secondly, it is the wettability of the bottom half of the 225 meter thick reservoir zone that affects the production profiles of the wells. The wettability of the top half of the reservoir zone hardly affects the production profiles at all.

Keeping control of the downhole pressure is important in any drilling situation, and especially when a narrow pressure window is experienced. The equivalent circulation density is influenced by rotation of the drillpipe, but there is no existing mathematical description for this behavior. In present project, existing knowledge of how drillpipe rotation affects pressure losses was presented, and used as a foundation in the development of empirical equations through regression analysis. Several data sets were gathered from various field studies, and a set of working equations was developed. The equations were presented in two different forms. One equation expressed pressure losses with rotation and without rotation, ΔPω≠0/ΔPω=0 vs. revolutions per minute. The three other equations describes ΔPω≠0/ΔPω=0 vs. Reynolds number, for selected rotation speeds.The four equations were tested for their accuracy by comparing with simulations performed in the software Drillbench®, by comparing with an existing mathematical model, and by comparing with virgin field data. All equations gave predictions close to the existing semi-empirical model. The equation described as a function of RPM predicted a smaller pressure loss ratio than the field study for a rotation speed of 60 RPM, but came within the results from this study for a rotation speed of 120 RPM. The equations expressed as a function of Reynolds number gave results closer to the semi-empirical model than the RPM-equation. All equations predicted a larger pressure loss than the simulations performed in Drillbench®, in some cases even twice as large. To further improve the equations, larger data sets have to be acquired. The quality of the equations will improve if they cover more situations, and if they are based on a wider spread in the data sets.

Drilling fluids make up an essential part of the drilling operation. Successful drilling operations rely on adequate drilling fluid quality. With the development of new drilling techniques such as long deviated sections and drilling in ultra-deep waters, the standard of required performance of the drilling fluids continue to increase. Narrow pressure margins and low tolerance for barite sag requires accurate prediction of the gel evolution in drilling fluids. Increased knowledge of how drilling fluids behave during low shear rates can lead to better design of drilling fluids to avoid settling of heavy particles at the wellbore. Settling of heavy particles at the wellbore can lead to serious incidents such as stuck pipe, lost circulation, poor cement jobs and well control difficulties. Studies on the gel evolution of oil based drilling fluids could be used to optimize hydraulic modelling and evaluate phenomena such as fluid loss, barite sag and cuttings transport.The objective of this report was to investigate the gel evolution, low shear viscosity and viscoelastic properties of oil based drilling fluids. Literature study and experimental investigations were performed on water based and oil based drilling fluids to extend the understanding of low shear viscosity of oil based drilling fluids.Literature study performed on low shear viscosity of drilling fluids confirmed that there is a need for improved models for describing dynamic yield point and low shear behaviour. A case study performed illustrates the relevance of the topic, and the consequences unexpected gel effects could have when drilling a well. Two water based drilling fluid samples and one oil based drilling fluid sample were prepared and tested. Quantitative information about the dynamic properties of drilling fluids was found. Flow curves and gel strength were measured using a Fann viscometer. Four different drilling fluid samples were investigated using an Anton Paar Physica rheometer. Oscillatory tests such as amplitude sweeps determined linear viscoelastic range (LVE). Determination of the linear viscoelastic range was necessary to further investigate viscoelastic properties by performing frequency sweeps within the LVE range. Both amplitude sweeps and frequency sweeps were performed at different frequencies and strains. The viscoelastic properties investigated were structure formation, structure breakage and low shear viscosity. The effect of variables such as temperature, frequency, time of rest on dynamic yield point and viscous and elastic modulus was investigated by varying these variables in series of experiments. Experiments performed conclude that there is little correlation between the dynamic yield point found from extrapolation of flow curves using the Herschel Bulkley model and the Bingham plastic model, and the dynamic yield point found from amplitude sweeps. Amplitude sweeps showed that the three samples of drilling fluids exhibit viscoelastic behaviour, and that the linear viscoelastic range in strain rate was approximately 1 % at a temperature of 20 °C and a frequency of 1 s-1 for all tested samples. Frequency sweeps showed that the elastic modulus dominates the viscous modulus within the LVE range for all three samples. Linear viscoelastic range and dynamic yield point were found to be temperature and frequency dependent. The properties of the different samples were found to not change monotonically with frequency or temperature. Results of experiments performed on a model water based drilling fluid conclude that time of rest had little influence on the properties even for longer period of rest. A slight increase in viscosity was observed for longer rest periods.

This master thesis investigates a combination of two different chemicalEOR methods: 1) polymer flooding and 2) deep profile control.The combination of these EOR methods are simulated by the useof ECLIPSE100 on a simplified synthetic 3D model (500m x 500m x36m). A 4 meter thick high permeability layer with a permeability of2000 mD is sandwiched between two low permeability layers of 100mD. For most of the simulations, the oil viscosity was 30 cp. After 30years of production, polymer flooding as a mobility control yieldedan additional recovery of 6.7% of STOOIP. The combination of mobilitycontrol and deep profile control almost doubled the effect andgave additional recovery of 11.3% of STOOIP. Sensitivity studies showedthat the effect of deep profile control is highly dependent on theextension of the partly blocked zone. The larger the blocking zone,the higher recovery by deep profile control. Saturation plots showedthat polymer flooding advances the water front in the low permeablelayers while profile control recover additional oil around the blockedarea inside the low permeable formation. The two methods have adual advantage and produce additional oil that is complementary toeach other. In this master thesis it has been shown that the concept ofcombined polymer flooding and profile control is a highly promisingcombined recovery method, and a method that should be consideredwhen evaluating a development scheme.

The governing requirements and regulations for petroleum activities on the Norwegian Continental Shelf (NCS) refers to the industry standard NORSOK D-010 for technical and functional requirements for Plug & Abandonment (P&A) operations. The last revision of this document was done in 2004, and since then, a lot has happened in the area of P&A technology development.This report will first describe the current NORSOK D-010 barrier requirements for P&A operations. Based on these requirements, an evaluation of cement materials and additives will follow, and also an evaluation of the newly developed alternatives ThermaSet and Sandaband as potential plugging materials. These materials all turns out to be potentially good alternatives, and could beneficially replace cement in certain environments and conditions to save time, money, and ensure better performance as a sealing material.However, at the time of the last revision, the NORSOK D-010 standard was mainly based on cement as the standard plugging material, and should therefore be more generalized and optimized for the implementation of the new materials. After evaluating the plugging materials, this report will make proposals for adjustments in the NORSOK D-010 to better implement the new alternative materials. The proposed changes include generalization of the requirements for cement, updates and inclusion of more information in well barrier schematics, and development of new specific requirements for the two new alternative materials.In the end, the proposed changes will be evaluated to assess if the adjustments would increase or reduce the level of safety in the NORSOK D-010 standard. Most of the proposed adjustments are expected to increase the level of safety, and none of the changes are expected to lower the level of safety in the standard.The next revision of NORSOK D-010 has already been announced, and is expected to finish late 2012. Other areas that should be assessed in the future are to develop and implement new standards for testing & qualification of alternative materials for use as barrier elements in P&A operations on the NCS, in addition to further development and improvement of new materials.

In this Master Thesis a method for estimating seabed p-wave velocities from normal mode seismic data is developed. This is done through forward modeling using two dimensional finite difference modeling to generate synthetic data based on a given parallel two layered laterally varying seabed velocity model and a constant two layered density model, with a common fixed water depth. A semblance inversion technique is developed in MATLAB using the period equation eqref{eq:period} and the resulting velocity profiles is plotted against the exact velocity model to check the validity of the estimates. The same method is extended to estimations of seabed densities. For analysis of the robustness of the method, analysis with added pseudo random noise is preformed.The results shows a good performance of the semblance method to reproduce the model velocity parameters. The introduction of noise is handled well and decent results are obtained for significantly low signal to noise ratios.It suggests that the semblance method is applicable to use for determination of other parameters influencing the normal mode response signal.