A great percentage of oil is observed to be left in the reservoir after the traditional primary and secondary recovery methods. This oil is described as immobile oil. Alkaline-Surfactants are chemicals used to reduce the interfacial tension between the involved fluids, while polymer is used in making the immobile oil mobile.Norne C-segment is in the decline stage and is facing considerable challenges regardingvolume of oil bye-passed due to water flooding. There is need for developing cost efficient enhanced oil recovery (EOR) methods that would be suitable for Norne fluid and rock properties and therefore improve sweep efficiency significantly. Based on literature and screening criteria, alkaline-surfactant-polymer can be used as an enhancing agent to produce extra oil and reduce water-cut significantly in the C-segment.The objective of this work is to evaluate the possibilities of using alkaline, surfactant and/or polymer to increase the oil recovery factor and prolong the production decline stage of Norne field. An initial study was conducted using heterogeneous synthetic models (with Norne Csegment fluids and rock properties) to assess the suitability of alkaline/surfactant/polymer (ASP) flooding. All the chemical cases simulated gave substantial incremental oil production and water-cut reduction. However, history matched Norne C-segment reservoir model was used to simulate alkalinesurfactant-polymer flooding using Eclipse 100. Appropriate chemical quantity for injection was ascertained by simulating several cases with different concentration, injection length and time of injection. Different sensitivity analyses were made and simulations revealed that the most effective method was not the most profitable. Having established most profitable method which was injecting ASP slug with a concentration of 7Kg/m3, 2Kg/m3 and 0.3Kg/m3 into C-3H (injector) for 4-years in a cyclic manner, an incremental recovery factor of 2.61% was recorded and Net Present Value (NPV) was calculated to be 1660 x103MNOK

SummaryThe displacement of oil from reservoir rock pore spaces is a function of many interacting variables, amongst which the reservoir wetting state has been shown to be one of the important affected by the rock lithology, oil chemistry and brine salinity. A finding from previous research says that the injection brine into oil saturated core plug increased oil recovery. Based on this the objective of this master thesis is to investigate the effect of brine concentration on flow properties in two types of carbonate rocks for enhanced oil recovery (EOR) through imbibition and water flooding processes.The methodology used to evaluate the effect of brine concentration (BC) and chemical composition (CC) for oil recovery consisted on two stages. The first stage covers the literature review regarding the effect of brine concentration and chemical composition, including carbonates (chalk and limestone) characteristics. The second stage is related to the laboratory experiment which was performed using n-Decane oil, six (6) brines with different concentrations and chemical composition and the six (6) core plugs where four (4) “chalks” from Ekofisk (Norway) and the other two (2) “limestones” from Iranian field. The experiment was carried out in the laboratory of Institute of Petroleum and Technology (IPT), the materials, chemicals products, apparatus and equipments, methodology and procedures were provided by the IPT laboratory.To carry out the laboratory experiments, initially the two cores from Iranian were cleaned before being used. Different properties of brines, cores and oil were measured using different methods and procedures; and results were computed. Next, each core was saturated with one type of brine and after that flooded by n-Decane oil for establishment of initial water saturation and determination of volume of oil produced by drainage process at room temperature conditions at one bar. After that, all cores were aging about 15 days at room temperature condition. Finally, each core was flooded using brine by imbibition process at room temperature conditions.Results achieved were computed and discussed based on the literature review and compared with “A salinity (AS) Ekofisk core reference case” and similar studies. From this study was observed that the matrix block has a high porosity. The average porosity was about 40.24% of the volumes of large pores. The average absolute permeability was about 3.73 mD which is low because the microporous dominate the pore network. The average brine density (ρ) was about1.026 g/cm3 and pH was about 7.25. The initial water saturation varies between 14.58 to 28.50% and residual oil saturation among 22.49 to 62%. The sleeve pressure in the cylinder was kept from 15 to 28 bar. During waterfloodig was observed that the breakthrough pressure drop and time to increases when the oil recovery increase.The highest original oil in place (OOIP) was achieved in the low salinity (LS) core which was about 68.46% and the lowest was recorded in the C salinity (CS) core which was around 26.71%. The reason of the high and the low recovery is related with the effect of brine concentration and chemical composition of Sodium, Calcium, Magnesium and Sulphate, added in the solution. The main driving mechanism for low salinity waterflooding is believed to be multi component ionic exchange made possible by the expansion of electrical double layer. The permeability and porosity of the cores can be pointed as other factor. In general, it was showen that there is an increase in oil recovery as the salinity decreases.

Gas coning is the tendency of the gas to drive oil downward in an inverse cone due to the downward movement of gas into the perforations of a producing well thereby reducing oil production and the overall recovery efficiency of the oil reservoir. This work addresses gas coning issues in a naturally fractured reservoir via a numerical simulation approach on a single-well radial cross-section using the ECLIPSE 100 reservoir simulator. Matrix and fracture properties are modelled. Critical rate, breakthrough time and GOR after breakthrough is determined which is used to investigate the effect of matrix and fracture properties on gas coning effective reservoir parameters such as oil flow rate, matrix and fracture porosity, vertical and horizontal matrix and fracture permeability, matrix block size, etc. Results show that reservoir parameters that affect coning include oil flow rate, matrix and fracture porosity, matrix and vertical permeability, anisotropy ratio, perforated interval thickness, density difference and mobility ratio. While matrix block size and fracture spacing have no significant effect on gas coning.

I performed manual History Matching on the E-segment of the Norne field based on available production & pressure data. I used the obtained final match for future prediction. I performed Production Optimization by experimenting with increased and decreased water injection rates.

With the increasing number of drilled ultra-extended reach wells and complex geometry wells, the drilling limitation caused by excessive torque and drag forces must be further investigated. The wellbore friction being a main limiting factor in extended reach well needs to be studied with the new developed models.This master thesis presents an application of the new 3-dimentional analytical model developed by Bernt S. Aadnøy in the synthetic test and four real wells. Quite diverse wellbore trajectory and depth has been chosen for a better evaluation and comparison of the model with the measured data. In order to investigate the potential and limitation of the model, torque and drag analysis during the different operations such as tripping in, tripping out, rotating off bottom, combined up/down were investigated. An application of the analytical model for wellbore friction analysis in the actual wells is very time consuming and requires a lot data/input manipulation. As a part of the thesis assignment, it was required to create simplified means for application and testing the analytical model. With visual basic application in Excel a simple torque and drag simulator was created purely based on the analytical model simple solution. Along with the analytical model the master thesis includes Wellplan software for torque and drag analysis in all the included test and actual wells. Along with this, the project has a brief literature study of 3D analytical model and torque and drag concept in general. The analytical model gives a reasonable torque and drag results. Based on comparison between the model and actual measurement, it has been observed that the analytical model simple solution in some cases may not precisely describe wellbore friction analysis. The discrepancy between Wellplan and the analytical model prediction occurs during the tripping in operations. Being a strong function of tension/compression in the drill string the analytical model for more accurate torque and drag prediction requires an application of the complete solution. The main challenge for this model is the complexity of its full application. There is an uncertainty regarding the model application in conjunction with drillstring effective tension. For the actual well application it is time consuming and requires drillstring effective tension analyzing which make the model disable for the real time analysis.The analytical model must be further investigated by application in the real well with good quality of measured data.

This research is a simulation study to improve total oil production using ASP flooding method based on simulation model of Norne field C-segment. The black oil model was used for simulations. Remaining oil in the reservoir can be divided into two classes, firstly residual oil to the water flood and secondly oil bypassed by the water flood. Residual oil mainly contains capillary trapped oil. Water flooding only is not able to produce capillary trapped oil so that there is a need for additional technique and force to produce as much as residual oil. One way of recovering this capillary trapped oil is by adding chemicals such as surfactant and alkaline to the injected water. Surfactants are considered for enhanced oil recovery by reduction of oil–water interfacial tension (IFT). The crucial role of alkali in an alkaline surfactant process is to reduce adsorption of surfactant during displacement through the formation. Also alkali is beneficial for reduction of oil-water IFT by in situ generation of soap, which is an anionic surfactant. Generally alkali is injected with surfactant together. On the other hand, polymer is very effective addition by increasing water viscosity which controls water mobility thus improving the sweep efficiency.In the first place, ASP flooding was simulated and studied for one dimensional, two dimensional and three dimensional synthetic models. All these models were built based on C-segment rock properties and reservoir parameters. Based on test runs, well C-3H was selected and used as a main injector in order to execute chemical injection schemes in the C-segment. Five studies such as polymer flooding, surfactant flooding, surfactant-polymer flooding, alkaline-surfactant and alkaline-surfactant-polymer flooding were considered in the injection process and important results from simulator were analyzed and interpreted. Sensitivity analyses were done especially focusing on chemical solution concentration, injection rate and duration of injection time. The polymer flooding project in this study has shown a better outcome compared to water flooding project. Economically best ASP solution flooding case is the flooding with concentration of alkaline at1.5kg/m3, surfactant at 15kg/m3 and polymer at 0.35 kg/m3 injecting for 5 years. AS flooding case for 4 years with alkali concentration at 0.5kg/m3 and surfactant concentration at 25 kg/m3 gave highest NPV value. It was found that surfactant flooding has a promising effect and it is more profitable than polymer flooding for the C segment in terms of NPV. Economic sensitivity analysis (Spider diagram) for low case, base case and high case at different oil prices, chemicals prices, and discount rate were also presented. It was found that change in oil price has significant effect on NPV compared to other parameters while polymer price has the least effect on NPV for high and low cases.

This study presents a detailed analysis of producing gas-oil ratio performance characteristics from conventional reservoir to unconventional reservoir. Numerical simulations of various reservoir fluid systems are included for comparison. In a wide sense of the word, the term of unconventional reservoir is including tight gas sand, coal bed methane, gas hydrate deposits, heavy oil gas shale and etc. In this study we specify the unconventional reservoir to only mean the low and ultra low permeability reservoir, which is including tight or shale reservoir. As an emerging research topic in the E&P industry, shale reservoir’s long-term well performance characteristics are generally not well understood (Anderson et al. 2010). Research methods and techniques for conventional reservoir are usually directly used in this unconventional reservoir analysis. These methods, however, have proven to be too pessimistic (Anderson et al., 2010). Fit-for-purpose approaches or solutions should be introduced in this new topic. Recently, hydraulic fracturing treatment is commonly used in the low matrix permeability reservoir to attain an economic production rate. The difference of well production performance between conventional reservoir and unconventional reservoir is not well known. In this study, we are trying to give a quantitative analysis in order to answer this question.In this study, a “generic” reservoir from field data with constant reserves and size were assumed. This reservoir model is homogeneous and of constant porosity, permeability and initial water saturation. In order to compare the production performance, fluid systems are varied from volatile oil to near critical oil, to gas condensate and to wet gas. The permeability of the reservoir model is also designed from high (conventional reservoir) to ultra low (unconventional), which ranges from 101 to 10-5 mD. Influence from fracture is especially considered because fractures in the low permeability reservoir provide a high conductivity that connects the reservoir matrix to the horizontal well. Fractures in the model are designed with identical geometrical characteristics (length, thickness) and of inner homogeneous properties (porosity, permeability).A black-oil model is used for each reservoir, and its PVT properties are generated with a 31 components EOS model using Whitson-Torp procedure (Whitson et al., 1983). Reservoir fluid systems equilibrium calculation in the black-oil model is done using the initial gas-oil ratio. We have compared the well’s production performance for each fluid system.Based on the industry experience, two standards are used in reservoir simulation control: gas production rate and cumulative revenue. The gas production rate with 10 ×106 ft3/day in the first 10 days or the cumulative revenue equal to 5 ×105 USD from the first 10 days is set as the standard for the commercial well rate. All of these simulations are run under the control of these two types which have just been mentioned. A case of liquid rich gas reservoir is analyzed systematically, to compare its production performance when reservoir permeability is changed from high to low. We are interested in how much oil or gas condensate can be extracted from the “reservoir” if same initial fluids in the reservoir but of a different permeability. This study is useful and practical, particularly for the industry in the era of “high” oil price and “low” gas price in North America.The simulation results show that we can extract more liquid from the reservoir if the matrix permeability is higher, particularly for the reservoir with initially large oil contents (volatile oil reservoir, near critical reservoir and gas condensate reservoir). Fracturing treatment in unconventional reservoir is required to attain an economic production rate. We also realize that for the required number of fractures and reservoir’s matrix permeability, there exists linear correlation in log-log plot in the low-permeability reservoir. In this study, the unique optimization software Pipe-It and reservoir simulator SENSOR are used. Optimal simulation results of permeability combination are obtained by the module Optimizer in Pipe-It.

In this study, based on the work of Vogel, we generated the Inflow Performance Relationship (IPR) curves and its dimensionless form at any stage of depletion using black-oil simulator results. The IPR was generated for horizontal well with gas and water coning problems, producing from thin oil reservoir sandwiched between gas cap and aquifer. Two empirical IPR equations adopted from SPE paper by Whitson was also presented here. The first empirical relationship was developed based on simulated data for each reservoir pressure (stage of depletion) while the second relationship was developed based on all generated data.A fully implicit black-oil Cartesian model with total grid number of 1480 and 150 ft total thickness was used as reservoir model. The horizontal well extends through the full length of reservoir in y-direction with only one grid number along the horizontal section which makes the model a 2D problem. Sensor reservoir simulator and Pipe-It software were utilized to generate the IPR data.This work also includes a sensitivity study to understand the effect of several parameters to gas and water coning behavior, well placement optimization, coning collapse study, and the effect of coning to maximum well production rate. In coning collapse study, a relationship between flowing bottom-hole pressure and reservoir pressure when the cone collapse is provided in graphical form. This could be useful in field application where chocking the well to lower flowing bottom-hole pressure has become one alternative to reduce coning problems.

Water coning is a complex phenomenon that depends on a large number of variables which include among others: production rate, perforation interval, mobility ratio, capillary pressure, etc. Its production can greatly affect the productivity of a well and the reservoir at large. In fractured reservoirs, the phenomenon is more complex owing to the high permeability of the fractures in the porous media. With this complexity in mind, water coning behaviour in fractured reservoir was studied by simulating a reservoir supported by a strong aquifer using ECLIPSE-100 Black-Oil Simulator. The water cut (WCT), oil production rate (OPR) and water saturation (BWSAT) at the producing interval (Block 1, 1, 7) were used to evaluate the coning phenomenon in a fractured reservoir. In the course of the study, sensitivity analyses on the modelled reservoir’s anisotropy ratio (kv/kh), production rate (q), storativity capacity (ω), fracture width (b) and fracture permeability (kf) were conducted to evaluate their effect on coning behaviour in fractured reservoir. The results obtained depict that while the anisotropy ratio is very significant in water cut and water saturation at the perforating interval it has no adverse effect on oil production rate. It was however, observed that the water cut and oil production rate decreased as the production rate (q) increased. Furthermore, the water cut, oil production rate and water saturation (BWSAT) from the fractured reservoir is sensitive to the storativity capacity (ω) depending on the fracture porosity (φf). Conversely, the fracture’s width (b) and permeability (kf) have no significant effect on the coning behaviour of the modelled fracture reservoir. However, anisotropy ratio (kv/kh), production rate as well as storativity capacity (ω) are significant parameters in evaluating coning phenomenon in fractured reservoirs.

To determine the carrying capacity of the drilling fluid, also determine the settling velocities of the drilling cuttlings. To produce the Reynold's number experimentally.