Realtime reservoir management is developed to manage a shrinking labor force and rising demand on energy supply. This dissertation seeks good strategies for realtime reservoir management. First, two simulatorindependent optimization algorithms are investigated: ensemblebased optimization (EnOpt) and bound optimization by quadratic approximation (BOBYQA). Multiscale regularization is applied to both to find appropriate frequencies for well control adjustment. Second, two gathered EnKF methods are proposed to save computational cost and reduce sampling error: gathered EnKF with a fixed gather size and adaptively gathered EnKF. Finally, oil price uncertainty is forecasted and quantified with three price forecasting models: conventional forecasting, bootstrap forecasting and sequential Gaussian simulation forecasting. The relative effect of oil price and its volatility on the optimization strategies are investigated. A number of key findings of this dissertation are: (a) if multiscale regularization is not used, EnOpt converges to a higher net present value (NPV) than BOBYQAeven though BOBYQA uses second order Hessian information whereas EnOpt uses first order gradients. BOBYQA performs comparably only if multiscale regularization is used. Multiscale regularization results in a higher optimized NPV with simpler well control strategies and converges in fewer iterations; (b) gathering observations not only reduces the sampling errors but also saves significant amount of computational cost. In addition, adaptively gathered EnKF is superior to gathered EnKF with a fixed gather size when the prior ensemble mean is not near the truth; (c) it is shown that a good oil price forecasting model can improve NPV by more than four percent, and (d) instability in oil prices also causes fluctuation in optimized well controls.

<p>Well cementing is one of the key processes performed during drilling and completion of wells. The main objective of primary cementing is to provide zonal isolation. Failure of cement to provide zonal isolation can lead to contamination of fresh water aquifers, sustained casing pressure, or blowout. For effective cementing, the cement slurry should completely displace the drilling fluid. In practice, this is hard to achieve and some mud is left in the wellbore where it contaminates the cement after cement placement.</p> <p>This study investigates the effect of mud contamination of cement on the integrity of cement-formation interface. Flow-through experiments were conducted over 30-day periods using cement-sandstone composite cores and brine (salinity ~20,000 ppm) at 2100 psi (14.48 MPa) confining pressure, temperature of 72°F (22.22°C) and flow rate of 1 ml/min. Each cylindrical composite core was composed of half-cylinder Berea sandstone and half-cylinder Portland cement paste, with dimensions 12 in (30.48 cm) in length and 1 in (2.54 cm) in diameter. One composite core had no contaminated layer and each of the two other cores had a ~1.27 mm (0.05 in) thick layer of contaminated cement with 5% or 10% mud contamination by volume.</p> <p>Image based techniques used to characterize the composite cores revealed the presence of large non-circular pores (with as much as ~750 µm length and ~150 µm thickness) in the mud contaminated cement at the end of the core-flood. The large pores were higher in number in the 10% than in the 5% mud contaminated cement. The pores did not appear to be interconnected at the end of 30-day core-flood although leaching of the cement surrounding the large pores was observed. The porosity of the 10% mud contaminated cement was found to have increased from 0.65% to 12.53%.</p> <p>Based on the observations, we can conclude that large pores are created in cement due to the presence of mud contamination and the pores increase in number as level of mud contamination increases. Leaching of the cement surrounding the large pores may lead to interconnectivity of the large pores in the long run and result in loss of zonal isolation.</p>

Geothermal energy has gained a lot of attention recently due to several favorable aspects such as ubiquitously distributed, renewable, low emission resources while leveraging the advances in the associated technologies such as directional drilling and low enthalpy power generation plant. However, there are still many challenges such as the high initial capital cost of drilling and surface facilities, environmental risk of seismicity due to the induced disequilibrium in the formation, and sustainability of project over designed operational life. Traditional downhole heat exchangers (DHE) could potentially reduce the capital cost and the risk of seismicity, but they are unable to maintain a sustainable geothermal energy production over the operational life due to the rapid cooling down of formation in the vicinity of the wellbore. In this study, a novel DHE design is introduced to enhance the energy production rate as well as sustainability for mainly two types of geothermal reservoirs: saturated geothermal reservoirs and enhanced/engineered geothermal systems (EGS). Modeling of DHE is based on the concept of thermal resistance. A geothermal reservoir simulator is built reusing components of an existing blackoil simulator by adding thermal energy transport equations and fracture representation (discrete fracture network). Several verification and validation tests are carried out. Parametric studies are presented for various configurations of DHE and thermodynamic analysis is carried out for the binary power plant cycle. In addition, the geothermal reservoirs Camerina A and Raton Basin are presented as case studies for saturated geothermal reservoir and EGS, respectively. In saturated geothermal reservoirs, the performance of DHE is improved significantly by exploiting forced convection. For EGS, the overall heat extraction rate is also enhanced by adding DHE.

More than sixty percent (60%) of conventional hydrocarbon reservoirs which are potential CO2 repositories are sealed by tight shale caprock. The geochemical reactivity of shale caprock during CO2 diffusive transport needs to be included in the reservoir characterization of potential CO2 sequestration sites as slow reactive transport processes can either strengthen or degrade seal integrity over the long term. Several simulation results had predicted that influx-induced mineral dissolution/precipitation reactions within shale caprocks can continuously reduce micro-fracture networks, while pressure and effective-stress transformation first rapidly increase then progressively constrict them. This experimental work applied specific analytical techniques in investigating changes in surface/near-surface properties of crushed shale rocks after exposure (by flooding) to CO2-brine for a time frame ranging between 30 days to 92 days at elevated pressure and fractional flow rate. Initial capillary entry parameters for the shale were estimated from digitally acquired pressure data evolution. Flooding of the shale samples with CO2-brine was followed by geochemical characterization of the effluent fluid and bulk shale rock through ICP-OES, XRD, EDS and pH measurements. Nano-scale measurement of changes in internal specific surface area, pore volume and linear/cumulative pore size distribution (using the BET Technique) showed that changes in the shale caprock due to geochemical interaction with aqueous CO2 can affect petrophysical properties. The intrinsically low permeability in shale may be altered by changes in surface properties as the effective permeability of any porous medium is largely a function of its global pore geometry. Diffusive transport of CO2 as well as carbon accounting could be significantly affected over the long term. The estimation of dimensionless quantities such as Peclet (Pe) and Peclet-Damkohler (PeDa) Numbers that are associated with geochemical reactivity of rocks and acidic fluid transport through porous media gave insight into the impact of diffusion and reaction rate on shale caprock in CO2 sequestration.

The well-known condensate blockage problem causes severe impairment of gas productivity as the flowing bottom-hole pressure falls below the dew point in gas-condensate reservoirs. Hence, this study attempts to investigate the concept of modifying the spreading coefficient and wettability using low-cost surfactants in the near wellbore region, to prevent the gas flow problems associated with condensate buildup. This study also examines the effect of brine salinity and composition on wettability, spreading and adhesion in condensate buildup regions, to evaluate the ability of brine salinity/composition for enhanced gas productivity in gas-condensate reservoirs. In this study, experiments were performed at both ambient and reservoir conditions using reservoir fluids. Water-advancing and receding contact angles were measured using the Dual-Drop-Dual-Crystal (DDDC) technique and sessile drop method to characterize reservoir wettability and spreading behavior. Interfacial tension was measured using pendent drop shape analysis (DSA) technique and capillary rise techniques. Anionic and nonionic surfactants and nine multi-component brines varying in salinity as well as ten single-salt brines with two different salinities were tested. Oil-water relative permeabilities were generated by history matching condensate recovery and pressure drop data obtained from the coreflood experiments using Berea sandstone core. Wettability was altered from strongly oil-wet to intermediate-wet by the anionic surfactant. The declining trend of spreading coefficient resulted from the presence of surfactants indicating the possibility of enhanced gas productivity and condensate recovery by surfactants. Coreflood results substantiated the wettability alteration to intermediate-wet induced by the anionic surfactant and 82% improvement in gas relative permeability was obtained at ambient conditions. The variation of brine salinity and composition had little effect on wettability and interfacial tension in condensate-brine system. However, large water-receding angles were observed due to the condensate drop spreading on the quartz surface through changing brine salinity and composition. This spreading behavior was more pronounced in high salinity brine systems. This study thus demonstrates that surfactant-induced wettability alteration and spreading coefficient reduction have the benefits for improving gas and condensate production by mitigating the condensate blockage problem. This study also indicates the potential of controlling the spreading behavior of condensate using low salinity brines.

Non-Darcy flows are expected to be ubiquitous in near wellbore regions, completions, and in hydraulic fractures of high productivity gas wells. Further, the prevailing dynamic effective stress in the near wellbore region is expected to be an influencing factor for the completion conductivity and non-Darcy flow behavior in it. In other words, the properties (fracture permeability and β-factor) can vary with the time and location in the reservoir (especially in regions close to the wellbore). Using constant values based on empirical correlations for reservoirs/completions properties can lead to erroneous cumulative productivity predictions. With the recent advances in the imaging technology, it is now possible to reconstruct pore geometries of the proppant packs under different stress conditions. With further advances in powerful computing platforms, it is possible to handle large amount of computations such as Lattice Boltzmann (LB) simulations faster and more efficiently. Calculated properties of the proppant pack at different confining stresses show reasonable agreement with the reported values for both permeability and β-factor. These predicted stress-dependent permeability and β-factors corresponding to the effective stress fields around the hydraulic fractured completions is included in a 2D gas reservoir simulator to calculate the productivity index. In image-based flow simulations, spatial resolution of the digital images used for modeling is critical not only because it dictates the scale of features that can be resolved, but also because for most techniques there is at least some relationship between voxel size in the image data and numerical resolution applied to the computational simulations. In this work we investigate this relationship using a computer-generated consolidated porous medium, which was digitized at voxel resolutions in the range 2-10 microns. These images are then used to compute permeability and tortuosity using lattice Boltzmann (LB) and compared against finite elements methods (FEM)simulation results. Results show how changes in computed permeability are affected by image resolution (which dictates how well the pore geometry is approximated) versus grid or mesh resolution (which changes numerical accuracy). For LB, the image and grid resolution are usually taken to be the same; we show at least one case where effects of grid and image resolution appear to counteract one another, giving the mistaken appearance of resolution-independent results. For FEM, meshing can provide certain attributes (such as better conformance to surfaces), but it also adds an extra step for error or approximation to be introduced in the workflow.

Rotary drilling system vibration has long been associated with damaging the bit, the bottom hole assembly and drill string. Vibration has been traditionally measured in the bottom hole assembly, and been closely associated with the resonant behaviors. This paper proposes an improved physical laboratory model to explore the dynamic behaviors associated with vibration. This model includes contact with the borehole wall allowing a range of stabilization geometries while removing bit-formation interaction effects. The results of exercising the model help develop new insights into both vibration measurement diagnostics and mitigation strategy execution. Presented here is a review of other physical bottom hole assembly and drilling concepts, and a new novel model. Experimental investigation using the new model for a range of geometries is presented with recorded conditions, annotated video stills and analysis using regression and response surface methods. The analysis when compared to existing industry mitigation methods allows unique insight to the possible effectiveness of such methods. A mathematical simulation of the system was also performed and its results compared to laboratory tests. The work shows that a shaft system alone can generate stick-slip and whirl behaviors. Such behaviors occur in distinct regions. Another conclusion of this work is that a popular method for inferring stick-slip from acceleration measures is not reliable for the system used in this study.

The efficiency of the use of CO2 as a displacement fluid in oil recovery is hampered by the existence of an unfavorable mobility ratio that is caused by the large difference in viscosity between the injected fluid (CO2) and the reservoir fluids. This viscosity contrast results in early CO2 breakthrough, viscous fingering, gas channeling, and consequently, the inability of CO2 to effectively contact much of the reservoir and the oil it contains. Improvement of sweep efficiency and mobility control in CO2 injection require solutions to these problems. The use of surfactants and other chemical means for mobility control has been studied extensively and offer promising results, as they provide ways of increasing the viscosity of CO2 and/or block high permeability zones. One common problem that researchers encounter occurs when moving from core-scale experiments to field-scale implementation. Results obtained from laboratory experiments serve as inputs to reservoir simulators for modeling field-scale processes and estimating surfactant requirements. Generally, core-scale permeability is assumed to be homogeneous. While this assumption simplifies laboratory experiments and provides information of some flow properties, it does not present in-depth knowledge on the true heterogeneity of a reservoir system as a whole, and how the varying permeability affects recovery. Core-scale results also typically imply that chemical requirements for field-scale implementation are uneconomic. It is thereby crucial to develop a method to characterize scaling of results from the core-scale to the field-scale, especially as it pertains to the amount of chemical to use in this recovery method. This will provide an insight into the dynamics of water, oil, surfactant and CO2 flow within a stratified system using results obtained from laboratory experiments. This study focused on the development, evaluation and validation of scaling (dimensionless) groups for surfactant transport in porous media that affect sweep efficiency. The groups were obtained through dimensional and inspectional analysis and verified through practical laboratory coreflood experiments and numerical simulation. Design of experiments was used to generate an appropriate sample space for the dimensionless groups from which a model that is capable of predicting oil recovery and pressure difference is developed. The scaling groups derived correspond to existing scaling methods for homogeneous systems. Therefore, Dykstra-Parsons coefficient, VDP, was introduced so as to incorporate heterogeneity for the evaluation of surfactant requirements. Borchardt et al. (1985), Yin et al. (2009), Bian et al. (2012) and Emadi et al. (2012) have conducted experimental studies to understand the mechanism of foam generation and propagation from CO2 and surfactant solution in the presence of oil. The findings reported by these researchers were based solely on laboratory investigations as they did not utilize numerical simulation to further understand the behavior of their respective systems. One researcher, Ren (2012b), used history-matching to relate surfactant transport properties measured during core experiments to a simulator-derived Mobility Reduction Factor, MRF. While very good matches were obtained, Ren (2012b) reported that each of the fitted parameters that led to a good fit of pressure and saturation data may not represent actual foam physics. For the first time, a comprehensive study that interfaced laboratory experiments and numerical simulation, while maintaining realistic interactions between phases, was conducted. This research work led to the development of a process that can be used to design a CO2-surfactant oil recovery project. This process is very flexible, and can be applied to a wide range of reservoir types as long as there is physical commonality between the laboratory and field models. The process allows for the assessment of ranges of parameters such as surfactant concentration and Dykstra-Parsons coefficients so as to aid in the selection of the optimum and economic surfactant concentration and to account for uncertainties due to heterogeneity.

This study investigates foam delivery mechanisms in vadose-zone remediation by using Method of Characteristics (MoC). In such applications, dry foams are introduced into a porous medium which is initially at low saturation of water (Sw) containing pollutants such as metals and radionuclides. For vadose-zone remediation processes to be successful, the injected aqueous phase should carry chemicals to react with pollutants and precipitate them for immobilization and stabilization purposes. Typical remediation techniques such as water and surfactant injections are not applicable, because of the concerns about downward migration. As a result, understanding foam flow mechanism in-situ is key to the optimal design of field applications. This study mainly consists of two parts: Part 1, formulating foam model mathematically using method of characteristics (MoC) and fractional flow analysis; and Part 2, using the model to fit to experimental data. Results from Part 1 show that foam delivery mechanism is indeed very complicated, making the optimum injection condition field-specific. The five major parameters selected (i.e., initial saturation of the medium, injection foam quality, surfactant adsorption, foam strength, and foam stability) are shown to be all important, interacting with each other linearly and non-linearly. In addition, the presence of water bank ahead of stable foams conjectured in previous studies is confirmed. Results also imply that although dry foam injection is generally recommended, too dry injection condition is found to hurt this process due to slow foam propagation. The results from Part 2 reveals a few important insights regarding foam-assisted deep vadose zone remediation: (i) the mathematical framework established for foam modeling can fit typical flow experiments matching wave velocities, saturation history and pressure responses; (ii) the set of input parameters may not be unique for the fit, and therefore conducting experiments to measure basic model parameters related to relative permeability, initial and residual saturations, surfactant adsorption and so on should not be overlooked; and (iii) gas compressibility plays an important role for data analysis, thus should be handled carefully in laboratory flow experiments. Foam kinetics, causing foam texture to reach its steady-state value slowly, may impose additional complications.

The effects of shales on fluid flow in marine-influenced lower delta-plain distributary channel deposits are investigated using a three-dimensional ground-penetrating radar (GPR) data volume from the Cretaceous-age Ferron sandstone at Corbula Gulch in central Utah, USA. Using interpreted GPR data, we formulate a geostatistical model of the dimensions, orientations, and geometries of the internal structure from the subaerial exposure surface down to about 12 m depth. The correlation function between GPR instantaneous amplitude and shale index is built after statistical calibration of the GPR attributes (amplitude) with well data (gamma ray logs). Shale statistics are computed from this correlation function. Semivariograms of shale occurrence for ten accretion surfaces indicate only slight anisotropy in shale dimensions. Sequential Gaussian Simulation stochastically maps shales on variably dipping stratigraphic surfaces. Experimental design and flow simulations examine the effects of semivariogram range and shale fraction on breakthrough time, sweep efficiency and upscaled permeability. Approximately 150 flow simulations examine two different geologic models, flow in all three coordinate directions, 8 geostatistical parameter combinations, and 5 realizations for each combination of parameters. Analysis of the flow simulations demonstrates that shales decrease the sweep, recovery and permeability, especially in the vertical direction.