The world energy demand will grow and oil will continue to be a major part of the energy consumption. Enhanced Oil Recovery will play a key role in meeting the oil demand by increasing the low oil recovery factors in the world today. Half of the oil is still trapped in the reservoir after the production have ceased. The development of new technology has brought a renewed attention for chemical flooding. It has been recognized as a technically feasible method in the Norwegian Continental Shelf and is expected to become attractive. Norne C-Segment is a good candidate for chemical flooding based on screening, current drainage strategy and high water cut. The objects of this Master Thesis are to find an optimum chemical flooding strategy for the Norne C-Segment to maximise the profit from volume of incremental oil produced. The result of the project is based on Net Present Value calculation. Simulations are run in Eclipse on a simulation model of Norne C-Segment released by Center of Integrated Operations at NTNU and Statoil ASA. The model was not perfect history matched therefore an effort to look at the uncertainties in vertical barriers where done before applying chemicals.The Ile formation was chosen as the target formation because of the highest OIP and high oil saturation. A synthetic model of the target formation was build to optimize the chemical injection scheme. Based on the evaluation of the injection wells C-2H was best suited for chemical flooding. The chemicals applied are polymer, surfactant, alkaline and combinations of two or all of these chemicals. Surfactant and alkaline are primarily used to reduce oil-water Interfacial Tension and minimize the capillary forces that trap residual oil after waterflooding. Polymers are used as a mobility control to improve reservoir contact and flood efficiency.Based on the simulation results and economic evaluation polymer flooding is the best chemical flooding method with a net present value of 406 million USD in 2022. Norne C-Segment Ile formation is favourable for mobility control. Surfactant and alkaline cannot mobilize enough residual oil to pay of the cost of chemicals and is not economical attractive.

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 Alvheim reservoir is a turbidite reservoir, which means that the complex deposition makes it a difficult reservoir to perform predictions regarding reservoir content on. In the preceding project work (Eggen 2012) AVO analyses were performed on the twelve modelled scenarios that can be present in a turbidite reservoir. These modelled scenarios were to be compared with the analyses performed on the real data in this master’s thesis to see if the modelled scenarios can help to predict what answers to expect from the analyses performed on the real data. One post-stack data set consisting of Near and Far stacks covering the whole Alvheim field including all three hydrocarbon discoveries, and one pre-stack data set focusing on the oil discovery named Kneler were available for this thesis in addition to well logs from well 25/4-7. Naturally, it was the Kneler oil discovery that was focused on, and on the gathers from the pre-stack data the top reservoir could be identified by a clear AVO effect. Different AVO analyses were performed on this AVO effect and the results were compared with the results obtained from the project work. In addition to performing AVO analyses on the data it was interesting to see if it was possible to see how the reservoir changed when moving away from the well location on the seismic data. To increase the signal to noise ratio, super gathers around the well location were created in addition to super gathers at some distance away from the well to see if there were changes that were noticeable on the seismic.The AVO analysis was performed on the top oil sand (top reservoir) in the Heimdal Member located in the Lista Formation. An AVO crossplot was created from both data sets, where the area around the Kneler discovery was picked by hand on the post-stack data set to match the area that was plotted from the pre-stack data. The crossplot created from the post-stack data showed the best deviation from the background trend out of the two, and the anomaly could be classified as a class III AVO anomaly. It was also performed an AVO gradient analysis on the AVO effect on a pre-stack seismic gather and on a synthetic seismic gather created with a normal Ricker wavelet and velocities taken from well 25/4-7. Both AVO curves from these analyses had a negative intercept and a negative gradient, which also could classify them as a class III AVO anomaly. It was known in advance that the upper part of the reservoir consisted of unconsolidated interbedded sand-shale and it was expected that the results would match the results obtained from the modelled scenario of the unconsolidated interbedded sand-shale. However, this was not completely the case and the results from the analyses of the real data turned out to match the analyses for the modelled unconsolidated massive sandstone. Even if the analyses from this master’s thesis do not match the expected analyses performed in the preceding project work, they can be said to be correct. The error in comparison is due to the fact that the analyses in this master’s thesis are performed on the top of a section of unconsolidated interbedded sand-shale, but the top layer is actually a layer of unconsolidated massive sandstone. This means that when making assumptions it should not be taken for granted that the real data will match the modelled data, especially not if there are uncertainties related to the assumptions the modelling is based on.

Most of the large petroleum discoveries have already been made, but the demand for energy is still increasing. To meet the demands, new methods for getting the existing resources from the subsurface up to the surface have to be applied. These methods include the Enhanced Oil Recovery (EOR) methods, methods to increase the hydrocarbons production from already existing fields. Low Salinity Waterflooding is an EOR method which has been given a lot of attention the last decades, and it has shown a great potential both during laboratory experiments and field scale tests. Low Salinity Waterflooding is applied by injecting water with a lower salinity than the existing connate water. Doing this provokes some chemically and physically processes that together tend to enhance the recovery in some petroleum reservoirs. The amount of incremental oil produced is, however, very dependent on the initial reservoir properties. The purpose of this project was to investigate the possible options regarding low salinity waterflooding in ECLIPSE 100 through simulations of a synthetic reservoir model. Large wettability sensitivity was observed, indicating that the oil/water relative permeability, saturation and capillary pressure profiles play a major role during simulations when the BRINE option is activated. Results obtained after injection of brines with different salinities showed an increase in oil recovery with a decrease in salinity of the injected brines. An initial oil-wet reservoir with high residual oil saturation was observed to show the largest incremental recovery. A water-wet reservoir, however, resulted in the highest ultimate recovery. The reason for the increase in oil recovery could be seen in conjunction with a decrease in water production after breakthrough of the low saline brines. After investigating the options included for low salinity waterflooding in ECLIPSE 100, a field evaluation of the potential of this as an EOR mechanism was simulated. A sector model of the Frøy field was obtained from Det Norske Oljeselskap. Initial reservoir properties and earlier laboratory experiments from cores in the same zone as the sector model had indicated a potential for LSW as a way to increase the oil production in the field. When the salinity in the reservoir reached below 5 kg/m3 total dissolved salts (TDS), a reduction in residual oil saturation up to 7 % of PV was initiated. This reduction resulted in an up to 13 % increase in oil recovery of the initial oil in place during secondary recovery mode. Tertiary recovery mode showed almost the same incremental recovery as the secondary recovery mode. A decrease in water cut was observed in conjunction with breakthrough of the low saline brines.Even though the results obtained from low salinity waterflooding proved to be in the range of what was observed during earlier experiments from the Frøy field, the data added to the grid cells were no measured data. It should therefore be conducted new and accurate laboratory experiments, such that these data might be included in simulation models. This is especially important regarding parameters like relative permeability, saturation and capillary pressure. A full field investigation of the potential for low salinity waterflooding as a possible EOR mechanism should also be carried out, since the sector model only is valid for a small part of the reservoir. On the other side, as observed from simulation of a sector mode, the potential for low salinity waterflooding in the Frøy field seems to be large.

This thesis is divided into several parts. The first part deals with hydrate theory and where hydrates form in the gas-and oil-dominated systems. A review of how hydrate plugs is formed and a method for removing hydrate plugs safely is also included.Simplified HYSYS models of the upstream part of Ormen Lange and Snøhvit gas fields on the Norwegian Continental Shelf constituted the basis for answering the second part of the task. Data from private conversations, reports, slide presentations, and other documents were used to create the models.Based on the models, calculations were made on the injection rate and storage capacity of mono ethylene glycol (MEG) on Ormen Lange and Snøhvit. The same models and calculation methods were used to determine injection rates for both methanol (MeOH) and MEG on the same fields. All the results combined with literature were then used to compare the inhibitors’ properties to determine which one was best suited for use on the current fields. During rate calculations several cases were made to determine which factors have the greatest impact on the amount of inhibitor needed.It was found that hydrates are formed on the pipe wall in gas dominated pipelines, while they are formed in the bulk flow in oil-dominated systems. The heat transfer coefficient and the seabed temperature have great influence on the amount of inhibitor needed. MEG-rate and storage capacity on Snøhvit are very large. Ormen Lange needs a larger inhibitor injection rate than Snøhvit. MEG is better suited than MeOH as an inhibitor of long-distance multi-phase tie-backs such as Ormen Lange and Snøhvit.

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.

Hydrocarbon generation and migration modelling from the northern North Sea

In the work of this Master's thesis, the anisotropy parameters, epsilon and delta, for the reservoir and the cap rock on the Troll Field have been estimated. This was done using well logs from 35 wells, including the P-wave sonic log and the inclination angle log of the wellbore. The velocity from the sonic log and the inclination angle were applied to a second order polynomial equation, which includes the anisotropy parameters.The Matlab software was utilized to perform the calculations and to generate plots necessary to estimate the parameters. To obtain more reliable results, different filters were applied to the data set for both the reservoir and the cap rock. The filters consisted of different intervals of porosity, acoustic impedance and depth, both individually and combined in different ways. In advance of the filtering, histograms were made for porosity, acoustic impedance and depth to look at the distribution of each, in order to find the range the different parameters could be filtered for.This process resulted in the following estimations of the anisotropy parameters for the reservoir: epsilon = -0.08 and delta = -0.03. The anisotropy parameters for the cap rock, which is a shale in most of the wells, was estimated as follows: epsilon = 0.11 and delta = 0.06. These parameters were applied in an AVO analysis, performed for the vertical well 31/2-L-41. An approximation using 3-term Shuey equation was applied for this purpose. The anisotropic case was compared with the isotropic case. This showed that there is an evident difference between the isotropic and the anisotropic model at large offsets. The exact solution from the Zoeppritz's equations was also included for comparison. This proved to be very close to the approximate solution.Amplitude values from seismic gathers were included in the AVO analysis. This showed that the amplitudes from the gathers increased with incidence angle, as for the isotropic and the anisotropic model. However, the increase in amplitude was much less than for the models.From this work, the estimation of the anisotropy parameters were shown to have a large uncertainty, even after filtering. To make the estimation of delta more stable, more deviated wells to cover the whole inclination angle range, especially from 27-40 degrees, are required. Epsilon is dependent on the vertical and the horizontal P-wave velocity only, thus there should be less uncertainty in estimating this parameter.From the AVO analysis, including the amplitudes from the gathers, no conclusive statements could be established due to the fact that the amplitude values had to be scaled to fit the amplitude values with the models. The amplitudes of the gathers were scaled to the amplitude of the isotropic case at far offset, thus the result could have been altered if scaled to the anisotropic case.

As warm oil or condensate from the reservoir flow through a pipeline on the cold sea bottom, wax often precipitate and deposit on the wall. To predict the rate of the deposition, wax modeling is important. The main mechanism contributing to deposition, molecular diffusion, is driven by a radial concentration gradient. The concentration gradient is driven by the radial temperature gradient. When precipitation of wax crystallites occurs in the bulk of the flow, it affects the concentration gradient, which again affects the rate of deposition. The current thesis gives an elucidation of this particularity. Fundamental heat and mass transport equations are solved numerically in Matlab and the result shows that the concentration profiles become slighter as the precipitation become larger. This decreases the mass flux due to molecular diffusion. A term “shear dispersion” was introduced in 1980’s to describe particle deposition of wax. The term has been used in several wax deposition models, but the mechanisms behind are not well explained in the literature. An elucidation of both a shear induced lift force and shear induced diffusion are investigated.

In this thesis a full well design and detailed tubing design has been developed for the HPHT well K-14. Wellcat™ casing design software has been used for tubing string analysis. K-14 has been designed using the same conditions as for wells in the Morvin HPHT field. The main issues related to this specific well design are the completion of the reservoir section, the tubing design with all relevant loads, and a HPHT well design with flexibility for intervention and stimulation by hydraulic fracturing. The reservoir drainage plan is based on wells with horizontal reservoir sections for optimal and cost effective recovery. The tubing has been designed and engineered for all the loads that the well may be exposed to during its lifetime. It is very important that all possible loads have been investigated, so the well complies with the HPHT requirements. The loads seen by the well can be divided in two groups: the loads induced by production and the loads during installation (qualification/pressure testing) and intervention.The focus of the well design has been to achieve optimal drainage with a simple and flexible solution to meet the requirements for intervention. Extreme loads may occur for wells in HPHT fields. There are additional aspects to consider when engineering these wells, such as steel and material degradation when exposed to high temperatures, and large temperature variations from production to bullheading with cold fluids. The effect of extreme temperature changes are seen by the liquids in the closed annuli, they will expand/contract resulting in an increase/decrease in pressure seen by the tubulars. The temperature variations will also affect sealing elastomers that are under high pressures, making them brittle and reduce/loose the sealing capacity. The aspects of well design and tubing design are discussed in detail through the development and engineering of the HPHT well K-14