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.

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.

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.

Installing an electrical submersible pump can be a way to increase the production in a well. This report will explain some ways the electrical submersible pump can be installed and describe the different components in an electrical submersible pump. The report will also give an insight in how electrical submersible pumps have been used and improvements done to the electrical submersible pump on two different fields. The main part will describe a method to screen wells and find out if installing an electrical submersible pump will be profitable. The method is to estimate future oil production, based on real-time production, with and without an ESP installed, and calculate the net present value. The method takes into account costs of installing, running and removing an electrical submersible pump. The ESP screening tool is screening the wells automatically. In addition it does an ESP simulation to find applicable pumps. For the ten wells screened by the ESP screening tool, the net present values have been negative, due to weak water cut estimation.

The knowledge of formation pore pressure, and how it changes throughout the length of a well, is crucial in terms of maintaining control of the wellbore. Failure to recognize deviations from the expected pressures can lead to problems and instabilities, which increases drilling costs. A worst case scenario may lead to loss of an entire well section. Thus maintaining a real-time knowledge of the formation pore pressure is beneficial regarding both the cost and the safety of a drilling operation.In this thesis multiple methods of pore pressure detection have been implemented in a Matlab program, which is used for testing with recorded real-time drilling data of a well, provided by IPT. The methods chosen were the Zamora and Eaton methods, both based on utilization of the dc-exponent, and the Bourgoyne-Young drilling model. The program has calculated pore pressure gradients based on each of these methods. In turn these results have been compared with the pore pressure presented in a final well report provided alongside the drilling data. This forms a basis for evaluation of each methods accuracy and applicability with use of this kind of drilling data. The results show that all three methods are able to produce a pore pressure gradient which is partly in compliance with the values provided in the final well report. However, the accuracy of the calculated results is not sufficient to be used to detect pore pressure with the desired precision. This may in part be caused by a lack of gamma ray data, which would have provided a more reliable selection of data. The addition of gamma ray as an input parameter should be of priority in any future developments. The most accurate result was calculated using the Bourgoyne-Young drilling model.