The temporary plug and abandonment (P&A) of old wells, and the following slot recovery, will be important for increasing the average rate of recovery from the Norwegian Continental Shelf (NCS). However, these operations faces challenges like high costs, safety concerns, environmental issues, and rapidly growing demand. Maintaining well integrity may be difficult when re-entering old wells. The demand for increased efficiency may lead operators to compromise on safety to finalize projects in time. This thesis tries to give a broad understanding of the well integrity issues on the NCS, and then tie these ndings around the term slot recovery operations. It will be important to understand the aspects which aects the lifetime of a well. Especially the long-term pressure, temperature and chemical effects on casings/tubings are important aspects to be understood. If this is done, one can increase the material lifetime in a well, and thus be able to re-use more of the casing strings in a slot recovery. These measures will help to keep marginal fields protable for a longer period. The thesis has also kept a strong focus on the challenges regarding the planning phase of a slot recovery operation. Of the essential factors in a slot recovery is to verify the old barrier envelope, and based on these findings create a robust operational plan. One of the mistakes which has been done in several slot recoveries is that the plan is created before any tests have been done. Once the plan is set and signed by the management, changes are harder to implement. Testing of the well often reveals unexpected factors which needs to be taken into consideration when planning an operation. Two separate slot recovery operations were also studied. They were carefully chosen to highlight typical issues with a slot recovery, and thus show that the theory fits with the reality. The requirements and guidelines for wells on the NCS also needs to be more customized for slot recovery operations.

In regular marine acquisition configuration, shallow sources and shallow streamers are used. Because of this configuration the high-frequency content of the seismic is favored, which is needed for sufficient vertical resolution. If the receivers were deployed at a larger depth the low-frequency content would be favored. The low frequencies are needed for inversion, deep penetration and visualization. However, this configuration would attenuate the higher frequencies and would suffer from poor vertical resolution. The attenuation of either high or low frequencies is a result of the receiver ghost, which attenuates higher frequencies for the deep tow, and lower frequencies for the shallow tow. Over/under acquisition method allows the wavefield to be separated into upgoing and downgoing wavefields. The configuration consists of 2 receiver-cables in vertical alignment with each other. By detecting only the upgoing wavefield, we are removing the receiver ghost and hence the frequency bandwidth should be broadened. These cables are towed at 18 and 25 meters, respectively. Regular receiver-cables are normally towed at 7 to 9 meters. Because of the deeper tow, the noise levels should also be lowered and result in a better signal to noise ratio. Post-stack seismic inversion is the process where we analyze the stacked seismic traces and try to reconstruct the velocity structure, or the acoustic impedance, of the sub-surface covered by the seismic. Inversion is sensitive to various parameters and small improvements in the seismic would result in improvements in the inversion volume. In the inversion configuration of this thesis, we are using a background model based on a-priori information from one known well. The a-priori information is used as an initial guess for the inversion to follow. To keep the inversion volumes as data-driven as possible, the inversions were processed with a weight factor on the initial model as low as possible, to enhance the changes made by the differences in the seismic volumes. Quantification of the difference in the inversion volumes based on different acquisition methods for the input seismic resulted in various comparisons of the acoustic impedance volumes. Difference in vertical resolution has been investigated and identified to have a relative difference in favor of the single cable seismic. The differences were due to a change in the wavelet shape and width and also change in dominating frequency of the respective time interval. Comparing the inversion volumes, based on the acquisition method, to their respective average inversion volumes identified changes in the inversion volumes due to feathering of the receiver cables. Further tests illustrated that the feathering had a significant impact on the inversion volumes. Since the feathering causes the receiver cables to deviate from a straight line astern of the vessel, the seismic volume is slightly changed compared to a volume where there is no feathering. Experiments illustrated that the frequency spectra are different. However, the frequency spectrum is not broadened, but shifted and shortened prone to lower frequencies. Dominating frequency was hence lower for cable combination seismic volumes compared to single cable seismic volumes. This resulted also in difference in the seismic wavelet as previously explained. Results indicate a significant change in inversion volumes due to fold, acquisition direction and feathering. Changes caused by the cable combination method were not as first anticipated. Since the method is used with a deeper tow, we were anticipating a significant change in the signal to noise ratio, also considering that receiver ghost is removed when evaluating only the upgoing wave. Results indicate that there was no significant change in signal to noise ratio. However, significant changes in the ratio were found when using the split spread method versus the single direction method (both single cable and cable combination method). This work concludes that the largest impact on the inversion volume is found where we have identified poor alignment of feathering, different acquisition direction and increased fold. The cable combination method doesn’t have significant impact on the inversion volume. Identified changes are quantified in this work and will verify these results.

Drilling in deep water is requiring more advanced technology as fields at greater depths are being discovered. Managed Pressure Drilling and Dual Gradient Drilling are both offering different techniques for navigating through the narrow pore pressure and fracture gradient window during an operation. Along with different drilling and development systems they are introduced as possible solutions to many of the challenges associated with deepwater drilling. The industry is looking into the possibility of doing highly deviated extended reach wells in deep water environments. Before doing so different simulations are done to investigate which factors will limit the maximum well trajectory and to figure out of far it is theoretically possible to drill in horizontal and vertical direction. With the help of the WELLPLANTM software a reservoir located in the Gulf of Mexico is chosen as a well candidate to run simulations on. Case study shows that for both directional extensions buckling of the drillpipe is what keeps us from drilling further. In terms of torque and pump capacity both rig candidates used for the study are well within their maximum capacities. Equivalent circulating density (ECD) would have been the main problem for the case study, but can easily be compensated for assuming we have the potential to control the pressure profile. With conventional drilling we would not be able to handle problems associated with ECD, meaning that DGD or other methods are required. From the sensitivity study we learn the importance of having access to accurate wellbore data, as a reduction in friction factor has the potential to extend the well trajectory even further and a potential dogleg severity would make us unable to reach target depth.

Oil and gas transport is today a vital part of the industry. Oil cooled during transport in pipelines may precipitate paraffin wax. Precipitated wax may deposit on pipe walls and cause flow restrictions. Deposition models are used to understand and predict deposition of solids. A deposition model can help predict wax problems before a pipe line is set into operation. If the amount of deposited wax is predicted it can help operators to develop removal plans and strategies. A total of 21 wax deposition experiments performed by others were digitized and evaluated. The logarithmic deposition-release model showed a good match with 18 of the experiments. The experiments tested the effect of varying flow rate, temperature or both. Most experiments behaved as expected when flow rate and temperature were varied. The deposition-release model consists of two coefficients, k1 and k2. Both coefficients were evaluated against wall shear stress for the varying rate experiments. The coefficients in the varying temperature series were evaluated against the temperature driving force. Linear trends between most coefficients and physical parameters were found. These linear trends lead to the development of four models that predict wax deposition. The models use either wall shear stress, the temperature driving force or both as an input. All models produce similar results. Each model was based on an experimental series. A study of a real pipeline with wax deposition was also investigated. Temperature and viscosity calculations matched well with values used in the study. The study reported calculated wax thickness based on measurements of pressure drop. The pressure drop method was evaluated and explained. The method does not consider an altered pressure drop due to increased pipe roughness and non-evenly distribution of deposits. Both of these effects will increase the pressure drop. It was found that neglecting these will cause the calculated thickness to be overestimated. Because of the overestimation of thickness it was hard to get an accurate match with models.

This study analyzes 2D seismic sections of extensional growth-fault basins, covering two tectonic realms; (i) Carboniferous rifting in Central Spitsbergen, and (ii) shallow Triassic extensional basins of the SE Svalbard region. The study of the Carboniferous Billefjorden Trough in Sassenfjorden-Tempelfjorden and from Reindalen, focus on the rift infill with associated wedge and lenticular shaped depocenter geometries. The two fundamental geometries are identified by either variable fault truncation of the wedge-shaped basin fill (fault onlap relationship) or fault-tip monoclines with associated basinward offset of the related lenticular basins. The interpretation of lines from Eastern Svalbard focus on a series of Triassic, shallow basins (< 200 m; up to 150 ms deep) of which most are bound by listric faults that sole out in underlying shale successions. These observations are correlated with similar faulting with basins in cliffs of Edgeøya. The offshore Triassic faulting of Eastern Svalbard represent a first assessment, as such analysis has not been carried out before. This study goes deeper into details on the evaporite-dominated Carboniferous Billefjorden Trough than those presented by Bælum and Braathen (2012). Some new information and characterization of the basin infill link seismic facies analysis of Carboniferous rifting to reflector belts that can be correlated with the pre-rift Billefjorden Group, the syn-rift successions of the Hultberget, Ebbadalen and Minkinfjellet formations, and the immediate post-rift (or late syn-rift) Wordiekammen Formation. The Billefjorden Trough is the result of a complex basin evolution history, and published results of outcrop studies in the northern Billefjorden area shows a basin that changes basin depocenter geometry, from a lenticular shape to a wedge shape and then back to a lenticular shape. Similar patterns are recognized by the seismic facies analysis. In a conceptual framework, the Billefjorden Trough differs from the rift basins described in Prosser (1993), in that the basin is significantly influence of fault-propagation folding, probably controlled by thick basin-center successions of low-shear strength evaporites. Encountered geometries are more similar to those of rift basins of the Gulf of Suez. Eastern Svalbard offers world class examples of extensional fault-growth basins in mountain slopes of Edgeøya and partly Hopen. Similar faulting is encountered in the lines interpreted from the Eastern Svalbard dataset, where the intricacy of faulting and their associated shallow basins of Triassic age offer complex geometries but also challenging interpretation work because of limited seismic resolution. Revealed internal geometries include rollovers and drag-folds, offering some general geometrical similarities with the much larger Carboniferous rifts. However, the depositional systems are very different. For the Triassic, regional clinoform progradation in a northerly direction interacted with the faulting, indicating that the coastal or deltafront migration at times were arrested by the faulting. This arrest is suggested by vertically stacked sequences, before the fault systems are bypassed by renewed clinoform progradation.

Since the environmental focus only becomes stronger and stronger in today’s society, industries like the oil and gas sector face some difficult challenges. Being the primary industry for CO2 production in the world requires them to invest a lot of resources in finding alternative methods to prevent venting to the atmosphere. Governments around the world are initiating measures and imposing taxes in order to compel the companies to do this. Injecting CO2 for EOR purposes has been around for several decades and is very well known to the industry. However, in more recent years, the idea of injecting CO2 for storage has become a promising method. Currently, there are several ongoing Carbon Capture and Storage (CCS) projects around the world, with more to come. The idea is to inject the CO2 into depleted reservoirs of aquifers, allowing different trapping mechanisms to react with the CO2 and prevent it from reaching the surface. CO2 features the ability to form an acid when dissolved in brine. At high pressures, the acid is very aggressive and could induce a strong dissolution reaction with carbonates. This could lead to severe consequence in a CCS project since carbonates are common material in oil and gas reservoirs. Dissolving the reservoir rock could increase the porosity. The fact that the rock’s stiffness and strength are strongly related to its porosity implies that alteration of the porosity could have a softening and weakening effect on the stiffness and strength in terms of softening and weakening. In addition to the porosity increase, other effects, such as chemical effects, can also be present, contributing to further alteration of the rock. In the assessment of CCS projects, geomechanical modeling requires input data describing the effects that the acid has on the rock mechanical properties. A correct representation of the reservoir requires a comprehensive understanding of every aspect. This requires a lot of research and studies on the rock mechanical alteration. Simulating subsurface processes in the laboratory is the first difficult challenge that has to be solved. Wormhole formation is dominates the dissolution pattern when acidic solutions are injected into core samples, but this is considered to be less representative for the reservoir processes, as a more homogeneous dissolution is assumed. The current project has successfully established that injecting a retarded acid allows full saturation before reaction takes place. Pre and post CT scanning has been performed together with special core analysis and mercury injection capillary pressure (MICP). A significant increase in porosity is seen in the tested rock material, Euville limestone, as a result of the treatments using retarded acid. After 6 treatments, an increase of 3 porosity units is observed. The study has emphasized the effect that chemical dissolution has on the rock mechanical properties, in terms of stiffness and strength. Failure tests have been performed for determining the Mohr – Coulomb failure envelope after a certain degree of alteration. Beside from the porosity increase, it also follows that the acid exposure also affects the stiffness and strength. A significant change is observed in the Young’s modulus, bulk modulus, shear modulus and Poisson’s ratio, having an average change of 9.4 ± 3.6 GPa, 1.8 ± 2.7 GPa, 4.5 ± 1.2 GPa and 0.12 ± 0.04, respectively, after 6 acid treatments. The failure line, for the treated rock, shows a clear reduction in strength with a 77 % decrease in the friction angle and a 26 % decrease in uniaxial compressive strength. Intuitively, since porosity, stiffness and strength are closely related, most of the effect is caused by the porosity increase. However, there are indications of that also other effects are causing the evolution for the stiffness parameters to deviate from the stiffness–porosity trends. The study has also approached the assessment of rock alteration from an acoustic velocity point of view. Increasing the porosity also results in reduced P- and S-wave velocities, as expected. Deviation from the porosity trend does, however, also suggest, that other effects influence the acoustic properties, in addition to the porosity increase. An evaluation of the dynamic moduli shows that fluid substitution is only effecting the measurements to a minor extent. The established protocol is necessary for further studies of the rock mechanical alteration that CO2 induces as it is injected into the reservoir. Our findings are important steps toward implementing knowledge on how the reservoir is affected by CO2 injection into geomechanical models and seismic monitoring. Being able to predict possible consequences and outcomes as well as monitoring of the reservoir, are very important tools for CCS projects and could potentially be the key to the license to operate.

Every year kick incidents occur, maybe best remembered by the Macondo blowout in April 2010 resulting in devastating oil spills throughout the Gulf of Mexico. Well control is one of the most important factors in any drilling operation, preventing disastrous blowouts where people and the environment will be affected. The development of new technologies has increased significantly, lowering the risks of blowouts, mostly because of the reliability of blowout preventers. Better hardware systems have been developed and better materials has increased the performance during critical parts of an operation. There are several causes why we encounter kicks; not keeping the hole full, lost circulation, swabbing, underbalanced pressures, trapped fluids/pressures and mechanical failures. Before an actual kick, there are warning signs that might occur and knowing how to interpret positive indicators of kick is very important. Pit gain, increase in return flow rate and abnormalities in drillpipe pressure are all signs that formation fluid has entered the well. When experiencing a kick, procedures to reduce the danger and the non productive time have to be started. Firstly the well has to be shut in by either the hard shut-in method or the soft shut-in method. Then the influx has to be circulated out of the well by the use of either the Driller’s Method or the Wait and Weight Method. To better understand and visualize the behavior of formation fluid entering the well, the simulation program Drillbench Kick has been used. The soft shut-in has been compared against the hard shut-in and the Driller’s Method has been run against the Wait & Weight Method. The simulations have been performed with both oil based mud and water based mud.

As the world's population is expanding, the global demand for energy will continue to increase. The global demand for all energy will grow by over 50 % the next 25 years. New technology and renewable energy will help us face these challenges, but an essential breakthrough in oil and gas production and exploration is also needed. The most common method for secondary oil recovery is water flooding implemented early during the primary production phase. This is done by forcing water down the injection wells in order to maintain reservoir pressure above bubble point, and to sweep the oil towards the production wells. Micro- and nano- technologies have already proved to be important in technical advances in a variety of industries, and the potential in upstream petroleum industry is great. Nanotechnology will have the ability to improve the industry when it comes to energy supply, by introducing technologies that are more efficient, and more environmental friendly. Many materials, tools and devices with qualities that cannot be matched by conventional technologies can be developed using nanotechnology. In this master's thesis I will look at the unique possibilities of using nanotechnology in oil and gas E&P. The thesis expands my project thesis, where I studied the potential for nanotechnology in exploration, drilling, production and especially enhanced oil recovery. Some believe that nanotechnology has the opportunity to increase the recovery factor up to 10 % in the future. This can be achieved by using for example tailored surfactant that can be added to the reservoir in a more controlled way than existing substances. Other applications could be “smart fluids” and new metering techniques for use in upstream petroleum industry. Experimental studies of the potential of hydrophilic silica nanoparticles have been carried out. Core flood experiments using Berea sandstone were performed to assess the potential in nanoparticle flooding. Permeability impairment was studied by flooding, and clear identification of retention was observed. It showed that concentration, injection volume and rate are important parameters when injecting particles through a porous media. Scanning Electron Microscope (SEM) was applied to detect any residual particles inside the core sample, which could explain permeability impairments. Further, implementations of silica nanofluid as both secondary and tertiary recovery method were tested. The results showed little mobilization when implemented as tertiary recovery method, but a clear reduction of residual oil saturation was observed when applying as secondary recovery method. Using nanoparticles in EOR is currently only tested at laboratory scale, but integrating this in large scale fields could improve the lifetime, recovery and make oil production even more economically beneficial. This thesis summarizes available information within the topic, and performs laboratory experiments in order to study the potential of hydrophilic silica nanoparticles for EOR purposes.

Today most of the oil is produced. This has triggered a wider interest for gas reservoirs. To determine how much gas that can be recovered in a reservoir it is important with good knowledge of the trapped gas saturation. This includes getting more information about trapped gas which demands more research in this area. Trapped gas saturation is recognized as an important factor in the process of recovering gas. In this project, literature has been studied and a lot of experimental work was done. Several papers have been read, and a basic knowledge of trapped gas, both what it is and how it can be determined, has been obtained. A main objective when reading was to gain knowledge about factors that affect the amount of trapped gas in a reservoir. In addition to reading about the theory, it has bee tested in the lab. The main purpose of the lab work was to see how rate change would affect the residual gas saturation, by using USS method. Spontaneous co-current imbibition experiments were also obtained. Six cores; three Berea plugs and three cores from the northern sea were chosen for execution of the experiments. In total 3-4 USS experiments were executed for every core, where an important area of study should have been to figure out how different pressure differences would affect the results. In addition one spontaneous imbibition experiment where done for each core. Normally water is used as the wetting phase. In this study IsoparL was chosen as the wetting fluid due to simplification factors in the lab. Previous studies of spontaneous imbibition experiments had shown good results when using IsoparL, so it was assumed that it could be used in USS experiments as well. It was discovered that IsoparL did not work well as the wetting fluid. By using this fluid, all the results obtained would be in the region of ΔP>0. So the most important conclusion obtained from this study is that water should be used as the wetting fluid when studying Sgr by using USS method. It was found that Sgr will decrease as rate increase when studying rates equal or larger than 4 ml/h with IsoparL as the wetting fluid.

The growing demand for energy has prompted oil companies to increase the production while paying more and more attention to the CO_2 footprint of their activities. To fulfill these requirements CO_2 storage and enhanced recovery have been tremendously developed in the last few years. Despite this consideration for lowering carbon emissions, the political incentives and the economic faisability of the projects, certain CO_2 pilot projects turn to be a failure. This study deals with a subject that has not been deeply under research so far but caused some EOR projects to be reconsidered: CO_2 EOR in the particular case of strong water-drive reservoirs. Despite the lack of field data on actual or previous projects, a simple one-dimensional model and some two-dimensional models were analysed with Eclipse 100 and Eclipse 300. The first part lists the CO_2 properties which will be implemented in the simulation files and describes the benefits of this type of tertiary recovery technique using carbon dioxide. Basic flow equations are applicable in the one-dimensional case and enable to determine the oil, water and CO_2 rate in a strong aquifer configuration. Both the blak-oil and computational simulations lead to concluding results which validated the derived equations. Further simulations permited to make a sensitivity analysis on the pressure drop or the distance between the wells, leading to optimum well location depending on the production needs. A better understanding of the model gave birth to a scaling number for the one-dimensional simulation that was verified by the construction of Walsh Diagrams. This model was further extended from one to two producers to account for gas losses due to the aquifer. It turns out that two scaling numbers are then necessary to describe this flow and eventually scale it up to real dimensions. Multiple-well simulations illustrated the effect of the aquifer on the CO_2 plume in the oil zone; however this loss in sweep efficiency needed to be quantified. A Matlab program was built in order to analyse the simulation pictures. By measuring the pixels of the plume compared to a reference area, the areal and vertical sweep efficiency were computed and gave a better feeling of the effect of the aquifer strength on the EOR process. For the model studied, the volumetric sweep efficiency falls from 15% for a weak aquifer, to 2% for a strong aquifer. The major part of the gas is blown away at a certain water rate which leads to a significant decrease in oil production for the production well next to the CO_2 injector. The industry has faced this problem for many years and some technological solutions turned out to be succesfull, this study can provide useful insights before implanting those solutions, by indicating the ideal well location and the expected fluid rates.