The goal of this research was to study the effect of salinity on the waterflood of initially oil-wet clay-rich sand packs. Two one-foot long sand packs with 8% initial water saturation and 50% porosity were aged in crude oil for two weeks and flooded with either a low salinity (1000 ppm NaCl, pH 6.3) or a high salinity (20000 ppm CaCl, 20000 ppm MgCl, 20000 ppm NaCl, 20000 PPM KCl, pH 6.2) brine. 1D low salinity floods yield an incremental oil recovery of 15% and a significant change in the relative permeability. Initial breakthrough brine analysis showed that the low salinity flood results in more cation exchange activity compared to the high salinity case. A pH change of up to 1.4 point was witnessed for the high salinity case whereas the low salinity case had a 1.1 point pH change. The pH stayed below 7 in both low salinity and high salinity cases. The relative permeability of the low salinity case indicates a more water-wet state than that of the high salinity flood. The 2D study focused on capturing the movement of the water saturation fronts in transparent 2D sand packs via digital recordings. Two-dimensional sand packs of the oil-aged clay-rich sands were constructed in plastic quarter 5-spot models. Secondary water floods were performed. Low salinity flooding yielded higher oil recovery at breakthrough than the high salinity case. There was more areal bypassing in the case of low salinity flooding. It was difficult to pack the 2D cells uniformly which affected the water floods. / text

Waterflooding has been used for many decades as a way of recovering oil from petroleum reservoirs. Historically the salinity of the injection water has not been regarded as a key variable in determining the amount of oil recovered. In recent years, however, evidence of increased oil recovery by injection of low salinity water has been observed in laboratories and fields. The technique is getting wider attention in the oil industry because it is more cost-effective than other EOR techniques. The present work demonstrates the synergy of low salinity water flooding and polymer flooding in the laboratory scale. The use of low salinity polymer solution in polymer flooding has significant benefits because considerably lower amount of polymer is required to make the solution of a target viscosity. Low salinity polymer flooding can also increase oil recovery by lowering residual oil saturation and achieve faster oil recovery by improving sweep efficiency. Several coreflood experiments were conducted to study the efficiency of low salinity water flooding and low salinity polymer flooding in mixed-wet Berea sandstone cores. All the core samples were aged with a crude oil at 90oC for 30-60 days before the tests. All the polymer floods were conducted in the tertiary mode. A synthetic formation brine (33,800 ppm) was chosen for high salinity water and a NaCl brine (1,000 ppm) for low salinity water. Medium molecular weight HPAM polymer, FlopaamTM 3330S was used due to the low/moderate permeability of the Berea sandstone cores used in this study. Coreflood tests indicate that injection of low salinity polymer solution reduces residual oil saturation by 5-10% over that of the high salinity waterflood. A part of the residual saturation reduction is due to low salinity and this reduction is achieved in less pore volumes of injection in the presence of polymers. Effluent ion analysis from both low salinity water flooding and low salinity polymer flooding showed a slight increase in divalent cation concentrations after the polymer breakthrough. Cation bridging may play a role in oil wettability and low salinity injection desorbs some of these cations. / text

Reservoir management strategies traditionally attempt to combine and balance complex geophysical, petrophysical, thermodynamic and economic factors to determine an optimal method to recover hydrocarbons from a given reservoir. Reservoir simulators have traditionally been too large and run times too long to allow for rigorous solution in conjunction with an optimization algorithm. It has also proven very difficult to marry an optimizer with the large set of nonlinear partial differential equations required for accurate reservoir simulation. A simple capacitance-resistance model (CRM) that characterizes the connectivity between injection and production wells can determine an injection scheme maximizes the value of the reservoir asset. Model parameters are identified using linear and nonlinear regression. The model is then used together with a nonlinear optimization algorithm to compute a set of future injection rates which maximize discounted net profit. This research demonstrates that this simple dynamic model provides an excellent match to historic data. Based on three case studies examining actual reservoirs, the optimal injection schemes based on the capacitance-resistive model yield a predicted increase in hydrocarbon recovery of up to 60% over the extrapolated exponential historic decline. An advantage of using a simple model is its ability to describe large reservoirs in a straightforward way with computation times that are short to moderate. However, applying the CRM to large reservoirs with many wells presents several new challenges. Reservoirs with hundreds of wells have longer production histories – new wells are created, wells are shut in for varying periods of time and production wells are converted to injection wells. Additionally, ensuring that the production data to which the CRM is fit are free from contamination or corruption is important. Several modeling techniques and heuristics are presented that provide a simple, accurate reservoir model that can be used to optimize the value of the reservoir over future time periods. In addition to optimizing reservoir performance by allocating injection, this research presents a few methods that use the CRM to find optimal well locations for new injectors. These algorithms are still in their infancy and represent the best ideas for future research. / text

Many attempts have been made to control water conformance. It is very costly to produce, treat and dispose of water, and produced water represents the largest waste stream associated with oil and gas production. The production of large amounts of water results in: (a) the need for more complex water?oil separation; (b) corrosion of wellbore and other equipment; (c) a rapid decline in hydrocarbon production rate and ultimate recovery; and (d) consequently, premature abandonment of a well or field, leaving considerable hydrocarbons unproduced. Sometimes water production results from heterogeneities in the horizontal direction, which leads to uneven movement of the flood front and subsequent early breakthrough of water from high permeability layers. This problem is exacerbated if there is (vertical) hydraulic communication between layers so that crossflow can occur. One of the novel technologies in chemical enhanced oil recovery (EOR) is a gel type called deep diverting gel (DDG), which describes material that functions by plugging thief zones deep from the well where they were being injected. To evaluate the performance of this new treatment method, we will (1) model the treatment methods, (2) conduct economic analysis, and (3) compare different EOR methods. We have conducted relevant literature review about the development, design, modeling and economics of the enhanced oil recovery methods. Schlumberger's Eclipse simulator software has been used for modeling purposes. Modeling runs have demonstrated that placement of a DDG in a high permeability zone provided a blockage that diverted water into lower permeability areas, thus increasing the sweep of target zones. Research results demonstrated that, although higher recovery can be achieved with a polymer flood, the combination of delayed production response and large polymer amounts cause such projects to be less economically favorable than deep gel placement treatments. From results of several sensitivity runs, it can be concluded that plug size and oil viscosity are two determining factors in the efficiency of DDG treatments. For the assumed case, economic analysis demonstrated that DDG has the most positive net present value (NPV), with polymer flooding second and simply continuing the waterflood to its economic limit the least positive NPV.

This study is to establish a binomial lattice method to apply real options theory to valuation and decision making in the petroleum exploration and production industry with a specific focus on the switching time from primary to water flooding oil recovery. First, West Texas Intermediate (WTI) historical oil price evolution in the past 25 years is studied and modeled with the geometric Brownian motion (GBM) and one-factor mean reversion price models to capture the oil price uncertainty. Second, to conduct real options evaluation, specific reservoir simulations are designed and oil production profile for primary and water flooding oil recovery for a synthetic onshore oil reservoir is generated using UTCHEM reservoir simulator. Third, a cash flow model from producing the oil reservoir is created with a concessionary fiscal system. Finally, the binomial lattice real options evaluation method is established to value the project with flexibility in the switching time from primary to water flooding oil recovery under uncertain oil prices. The research reaches seven conclusions: 1) for the GBM price model, the assumptions of constant drift rate and constant volatility do not hold for WTI historical oil price; 2) one-factor mean reversion price model is a better model to fit the historical WTI oil prices than the GBM model; 3) the evolution of historical WTI oil prices from January 2, 1986 to May 28, 2010 was according to three price regimes with different long run prices; 4) the established real options evaluation method can be used to identify the best time to switch from primary to water flooding oil recovery using stochastic oil prices; 5) with the mean reversion oil price model and the most updated cost data, the real options evaluation method finds that the water flooding switching time is earlier than the traditional net present value (NPV) optimizing method; 6) the real options evaluation results reveals that most of time water flooding should start when oil price is high, and should not start when oil price is low; and 7) water flooding switching time is sensitive to oil price model to be used and to the investment and operating costs. / text

Although the global energy demand is shifting towards a well-balanced energy mix, fossil fuels will continue to have a significant role in this transition and will maintain a big share in the energy mix portfolio. The production of oil and gas has already reached the apex in the time that most of the conventional giant reservoirs are depleting, and discoveries for new reserves have shrunk down. In conventional reservoirs, it is estimated that about two-thirds of the Original Oil in Place (OOIP) will not be produced within the field lifecycle, corresponding to an average Recovery Factor (RF) between 20% and 40%. This low recovery factors from traditional methods trigger more investments in the Enhanced Oil Recovery (EOR) techniques. Waterflooding is one of the most commonly used technique to increase RF by raising or maintaining reservoir pressure. Lack of comprehending the driving forces in Naturally Fractured Reservoirs and reservoir heterogeneity may lead to serious conformance problems in which dealing with excessive undesirable water production becomes very challenging. Chemical EOR through an injection of a polymer solution is amongst the tested options that can be used to improve sweep efficiency. Ultimately, understanding the reservoir characteristics and having the know-how to implement the best recovery option will help to maximize the field’s lifecycle and increase the RF. Therefore, this study investigates some key elements that have a significant influence on the overall fluid flow behavior. The work reveals insights on the impact of capillarity and wettability in heterogeneous porous media. An experimental lab-scale consisting of a 2D sandbox model, which mimics a water-wet fractured system with injection and production ports, was designed, fabricated, and tested in single-phase and two-phase flow scenarios including the injection of water and polymer solutions. In the case of single-phase flow, a waterflood baseline scenario was studied with controlled variables, which helped to distinguish the contrast with the polymer flood case. Implementing water injection in a fractured water-wet reservoir showed that water prefers to channel through high permeable streaks, which consequently leads to poor volumetric sweep leading to significant bypassed zones. Investigating the two-phase flow was the essence of this research. Thus, the same procedures were repeated where water and polymer were used to displace oil. During waterflooding, due to strong capillarity contrast between the matrix and fracture media, flow divergence was found to be faster towards the matrix medium where the matrix gets saturated faster than that the fracture, overriding the high permeability of the fracture. Whereas, polymer flooding exhibited better volumetric sweep in all scenarios. Numerical simulations were used to replicate the experiments. This work can give new visual insights about key recovery mechanisms in heterogeneous reservoirs using polymers.

Waterflood optimization via rate control is receiving increased interest because of rapid developments in the smart well completions and I-field technology. The use of inflow control valves (ICV) allows us to optimize the production/injection rates of various segments along the wellbore, thereby maximizing sweep efficiency and delaying water breakthrough. It is well recognized that field scale rate optimization problems are difficult because they often involve highly complex reservoir models, production and facilities related constraints and a large number of unknowns. Some aspects of the optimization problem have been studied before using mainly optimal control theory. However, the applications to-date have been limited to rather small problems because of the computation time and the complexities associated with the formulation and solution of adjoint equations. Field-scale rate optimization for maximizing waterflood sweep efficiency under realistic field conditions has still remained largely unexplored. We propose a practical and efficient approach for computing optimal injection and production rates and thereby manage the waterflood front to maximize sweep efficiency and delay the arrival time to minimize water cycling. Our work relies on equalizing the arrival times of the waterfront at all producers within selected sub-regions of a water flood project. The arrival time optimization has favorable quasi-linear properties and the optimization proceeds smoothly even if our initial conditions are far from the solution. We account for geologic uncertainty using two optimization schemes. The first one is to formulate the objective function in a stochastic form which relies on a combination of expected value and standard deviation combined with a risk attitude coefficient. The second one is to minimize the worst case scenario using a min-max problem formulation. The optimization is performed under operational and facility constraints using a sequential quadratic programming approach. A major advantage of our approach is the analytical computation of the gradient and Hessian of the objective which makes it computationally efficient and suitable for large field cases. Multiple examples are presented to support the robustness and efficiency of the proposed optimization scheme. These include several 2D synthetic examples for validation purposes and 3D field applications.

This thesis provides a novel investigation into rainfall-runoff processes occurring within a unique two-tiered depth-driven overland flow physical modelling environment, as well as within a numerical model context where parameterisation and DEM/building resolution influences have been investigated using an innovative de-coupled methodology. Two approaches to simulating urban rainfall-runoff responses were used. Firstly, a novel, 9 m2 physical modelling environment consisting of a: (i) a low-cost rainfall simulator component able to simulate consistent, uniformly distributed rainfall events of varying duration and intensity, and; (ii) a modular plot surface layer was used. Secondly, a numerical hydroinundation model (FloodMap2D-HydroInundation) was used to simulate a short-duration, high intensity surface water flood event (28th June 2012, Loughborough University campus). The physical model showed sensitivities to a number of meteorological and terrestrial factors. Results demonstrated intuitive model sensitivity to increasing the intensity and duration of rainfall, resulting in higher peak discharges and larger outflow volumes at the model outflow unit, as well as increases in the water depth within the physical model plot surface. Increases in percentage permeability were also shown to alter outflow flood hydrograph shape, volume, magnitude and timing due to storages within the physical model plot. Thus, a reduction in the overall volume of water received at the outflow hydrograph and a decrease in the peak of the flood event was observed with an increase in permeability coverage. Increases in the density of buildings resulted in a more rapid receding limb of the hydrograph and a steeper rising limb, suggesting a more rapid hydrological response. This indicates that buildings can have a channelling influence on surface water flows as well as a blockage effect. The layout and distribution of permeable elements was also shown to affect the rainfall-runoff response recorded at the model outflow, with downstream concentrated permeability resulting in statistically different hydrograph outflow data, but the layout of buildings was not seen to result in significant changes to the outflow flood hydrographs; outflow hydrographs appeared to only be influenced by the actual quantity and density of buildings, rather than their spatial distribution and placement within the catchment. Parameterisation of hydraulic (roughness) and hydrological (drainage rate, infiltration and evapotranspiration) model variables, and the influence of mesh resolution of elevation and building elements on surface water inundation outputs, both at the global and local level, were studied. Further, the viability of crowdsourced approaches to provide external model validation data in conjunction with dGPS water depth data was assessed. Parameterisation demonstrated that drainage rate changes within the expected range of parameter values resulted in considerable losses from the numerical model domain at global and local scales. Further, the model was also shown to be moderately sensitive to hydraulic conductivity and roughness parameterisation at both scales of analysis. Conversely, the parameterisation of evapotranspiration demonstrated that the model was largely insensitive to any changes of evapotranspiration rates at the global and local scales. Detailed analyses at the hotspot level were critical to calibrate and validate the numerical model, as well as allowing small-scale variations to be understood using at-a-point hydrograph assessments. A localised analysis was shown to be especially important to identify the effects of resolution changes in the DEM and buildings which were shown to be spatially dependent on the density, presence, size and geometry of buildings within the study site. The resolution of the topographic elements of a DEM were also shown to be crucial in altering the flood characteristics at the global and localised hotspot levels. A novel de-coupled investigation of the elevation and building components of the DEM in a strategic matrix of scenarios was used to understand the independent influence of building and topographic mesh resolution effects on surface water flood outputs. Notably, the inclusion of buildings on a DEM surface was shown to have a considerable influence on the distribution of flood waters through time (regardless of resolution), with the exclusion of buildings from the DEM grid being shown to produce less accurate results than altering the overall resolution of the horizontal DEM grid cells. This suggests that future surface water flood studies should focus on the inclusion and representation of buildings and structural features present on the DEM surface as these have a crucial role in modifying rainfall-runoff responses. Focus on building representation was shown to be more vital than concentrating on advances in the horizontal resolution of the grid cells which make up a DEM, as a DEM resolution of 2 m was shown to be sufficiently detailed to conduct the urban surface water flood modelling undertaken, supporting previous inundation research.

Chemical EOR processes such as polymer flooding and surfactant polymer flooding must be designed and implemented in an economically attractive manner to be perceived as viable oil recovery options. The primary expenses associated with these processes are chemical costs which are predominantly controlled by the crude oil properties of a reservoir. Crude oil viscosity dictates polymer concentration requirements for mobility control and can also negatively affect the rheological properties of a microemulsion when surfactant polymer flooding. High microemulsion viscosity can be reduced with the introduction of an alcohol co-solvent into the surfactant formulation, but this increases the cost of the formulation. Experimental research done as part of this study combined the process of hot water injection with ASP flooding as a solution to reduce both crude oil viscosity and microemulsion viscosity. The results of this investigation revealed that when action was taken to reduce microemulsion viscosity, residual oil recoveries were greater than 90%. Hot water flooding lowered required polymer concentrations by reducing oil viscosity and lowered microemulsion viscosity without co-solvent. Laboratory testing of viscous microemulsions in core floods proved to compromise surfactant performance and oil recovery by causing high surfactant retention, high pressure gradients that would be unsustainable in the field, high required polymer concentrations to maintain favorable mobility during chemical flooding, reduced sweep efficiency and stagnation of microemulsions due to high viscosity from flowing at low shear rates. Rough scale-up chemical cost estimations were performed using core flood performance data. Without reducing microemulsion viscosity, field chemical costs were as high as 26.15 dollars per incremental barrel of oil. The introduction of co-solvent reduced chemical costs to as low as 22.01 dollars per incremental barrel of oil. This reduction in cost is the combined result of increasing residual oil recovery and the added cost of an alcohol co-solvent. Heating the reservoir by hot water flooding resulted in combined chemical and heating costs of 13.94 dollars per incremental barrel of oil. The significant drop in cost when using hot water is due to increased residual oil recovery, reduction in polymer concentrations from reduced oil viscosity and reduction of microemulsion viscosity at a fraction of the cost of co-solvent. / text

Submitted by Renata Lopes (renatasil82@gmail.com) on 2016-01-13T13:25:29Z No. of bitstreams: 1 pavelzenonsejaspaz.pdf: 1021401 bytes, checksum: 6c80da770310ced9141a330e3a4d4f9b (MD5) / Approved for entry into archive by Adriana Oliveira (adriana.oliveira@ufjf.edu.br) on 2016-01-25T17:32:38Z (GMT) No. of bitstreams: 1 pavelzenonsejaspaz.pdf: 1021401 bytes, checksum: 6c80da770310ced9141a330e3a4d4f9b (MD5) / Made available in DSpace on 2016-01-25T17:32:38Z (GMT). No. of bitstreams: 1 pavelzenonsejaspaz.pdf: 1021401 bytes, checksum: 6c80da770310ced9141a330e3a4d4f9b (MD5) Previous issue date: 2015-08-28 / CAPES - Coordenação de Aperfeiçoamento de Pessoal de Nível Superior / Neste trabalho apresentamos um estudo analítico sobre a recuperação de óleo pesado utilizando injeção de água, que é aquecida por meio de ondas eletromagnéticas de alta freqüência. Recentemente, foi feito um experimento (descrito em [12]), onde a água foi injetada num meio poroso, aquecida por meio de ondas eletromagnéticas. Os resultados do experimento mostram que o aquecimento mediante ondas EM melhora o deslocamento do óleo pela água. Desta maneira, apresenta-se a injeção de água com aquecimento por ondas EM como um método viável na recuperação de óleo. Consideraremos um modelo matemático simples descrevendo o experimento mencionado acima, que consiste de duas leis de balanço, uma para a energia e outra para a massa da água. O objetivo do trabalho é usar o Princípio de Duhamel e a Teoria das Leis de Conservação para encontrar soluções semi-analíticas deste modelo simplificado. Segundo [8], utilizamos o Princípio para achar a solução da equação de balanço de energia do tipo Convecção-Reação-Difusão para o problema de transporte de calor num meio poroso na presença de uma fonte de ondas eletromagnéticas. A equação de balanço para a massa da água é uma equação diferencial parcial não linear de primeira ordem do tipo Buckley-Leverett (Veja [4] e [7]). Ela será resolvida usando a Teoria das Leis de Conservação. Segundo [15], a solução deste problema contém ondas de rarefação e choque. / In this work, we present the results obtained by analytical study of heavy oil recovery by water flooding and electromagnetic (EM) heating of high frequency. Recently, an experiment was made, where water was injected into a porous medium, warmed by means of electromagnetic waves. The experiment results show that EM heating improves the displacement of oil by water. Thus, the water flooding combined with EM heating is a viable method for oil recovery. We consider a simple mathematical model describing this experiment consisting of two balance laws for energy and water mass. The goal is to use Duhamel’s Principle and the Theory of Conservation Laws to find semi-analytical solutions of this simplified model. We use the principle solve the energy balance equation of convection-reaction-diffusion type for heat transport problem in a porous medium in the presence of a source of electromagnetic waves. The balance equation for the mass of water is a nonlinear partial differential equation of first order of Buckley-Leverett type. It is solved using the Theory of Conservation Laws.