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.

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.

This thesis summarizes and concludes my master thesis research work. The main objective of this research was to develop a rigorous and generic forecast model for all the fields on the Norwegian Continental Shelf based on publically available data and free software. Pipe-It Norwegian Continental Shelf Integrator and Forecaster solution provides the opportunity to forecast oil and gas production rate and economics for all assets on the Norwegian Continental Shelf. The solution is automatically synchronized with an on line database, that is maintained by the Norwegian Petroleum Department. The solution currently contains 87 fields and handles thousands of application launches in parallel. The results can be filtered and aggregated for multiple engineering purposes, like the impact of new discoveries on future production rates and economics.

The world’s total oil reserves are to some extent dominated by heavy oil. The heavy oil reserves are doubled in volume compared to conventional oil reserves. As conventional oil reservoirs are depleting, heavy oil and bitumen possesses a great potential in covering parts of the future energy demand. The possibility of horizontal drilling has created a pathway for SAGD (Steam Assisted Gravity Drainage), which is the most preferred heavy oil and bitumen recovery method. The mechanism of SAGD involves two parallel horizontal wells, one for production and one for injection. The production well is situated at the bottom of the reservoir and the injection well is placed above. Steam is injected and heats up the oil which is then able to flow to the production well by gravity drainage. In the present thesis, a numerical study of parameters has been performed in relation to SAGD implementation in the Athabasca field. The thermal simulator utilized is CMG STARS. The Athabasca field is located in Northern Alberta in the Western Canada Sedimentary basin. Due to the complexity of core extraction in bitumen reservoirs, a comprehensive sensitivity analysis is significant in order to determine the appropriate production approach. The present study confirmed that a decrease in viscosity and increase in porosity yielded higher oil recoveries. All oil recoveries found in 3D simulations were within model uncertainties compared to the 2D result. Increase in horizontal and vertical permeabilities resulted in higher oil recovery up to a certain limit, where exceeding permeabilities provided limited increase in oil recovery. The effect of different vertical well spacing proved to have minor effect on amount of oil produced. Yet, based on cumulative steam oil ratio (CSOR) it was proposed to maintain a vertical well spacing in the range of 3.5 to 7 meters.

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.

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.