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.

Wettability is the ability of a fluid to spread or adhere on a rock surface in the presence of other immiscible fluids. Knowledge of wettability is important to decide what production strategy needs to be employed for optimum oil recovery. Wettability is affected by rock mineralogy, rock surface roughness, and brine compositions. Previous studies have dealt with solid-liquid-vapor systems and those involving wettability characterization in solid-liquid-liquid systems have used contact angle techniques known to have reproducibility problems. In this study, a new technique called the Dual-Drop-Dual-Crystal (DDDC) Technique has been used to characterize wettability in terms of dynamic contact angles. The Wilhelmy Plate technique has also been used to measure contact angles for a comparative evaluation of the DDDC results. In studying the effects of surface roughness, brine dilution and surfactant addition in crude oil-brine-rock systems, the Wilhelmy was found to be insensitive, while the DDDC showed significant effects of mineralogy, roughness, brine dilution and surfactant addition on dynamic contact angles. Study of the effects of brine dilution on dynamic contact angles was conducted using Yates brine and its diluted mixtures with deionized water in different proportions. In this study, interfacial tension has been measured using the Drop Shape Analysis (DSA) technique and the results have been compared with those obtained using the du Nuoy ring Tensiometer. A parabolic trend in interfacial tension was observed, with an initial decrease with increasing brine percentage in the mixture and then an increase after attaining a certain minimum. An unxpected effect of oil drop spreading on the rock surface yielding large contact angles was observed for certain brine dilutions. This spreading phenomenon was correlated to the receding angle and interfacial tension as discussed (24,36). A similar effect of oil spreading was also observed when using synthetic brine. This study investigated the effect of a nonionic surfactant on wettability. Initial oil-wet nature of the Yates system was rendered intermediate-wet at certain concentrations of the surfactant. At higher concentrations, the advancing angle decreased to a strongly water-wet angle, indicating the ability of the surfactant to alter the wettability of the crude oil-brine-rock system.

Maintaining underbalanced conditions from the beginning to the end of the drilling process is necessary to guarantee the success of jointed-pipe underbalanced drilling (UBD) operations by avoiding formation damage and potential hazardous drilling problems such as lost circulation and differential sticking. However, maintaining these conditions is an unmet challenge that continues motivating not only research but also technological developments. This research proposes an UBD flow control procedure, which represents an economical method for maintaining continuous underbalanced conditions and, therefore, to increase well productivity by preventing formation damage. It is applicable to wells that can flow without artificial lift and within appropriate safety limits. This flow control procedure is based on the results of a new comprehensive, mechanistic steady state model and on the results of a mechanistic time dependent model, which numerically combines the accurate comprehensive, mechanistic, steady-state model, the conservation equations approximated by finite differences, and a well deliverability model. The new steady state model is validated with both field data and full-scale experimental data. Both steady state and time dependent models implemented in a FORTRAN computer program, were used to simulate drilling and pipe connection operations under reservoir flowing conditions. Actual reservoir and well geometries data from two different fields, in which the UBD technique is being employed, were used as input data to simulate simultaneous adjustments of controllable parameters such as nitrogen and drilling fluid injection flow rates and choke pressure to maintain the bottomhole pressure at a desired value. This value is selected to allow flow from the reservoir to substitute for reduction or cessation of nitrogen injection during drilling and for interruption of nitrogen and drilling fluid circulation during a pipe connection. Finally, a specialized procedure for UBD operations is proposed to maximize the use of natural energy available from the reservoir through the proper manipulation of such controllable parameters based on the results of the computer simulations.

Over 8,000 wells in the Gulf of Mexico exhibit sustained casing pressure (SCP). SCP is defined as any measurable casing pressure that rebuilds after being bled down, attributable to cause(s) other than artificially applied pressures or temperature fluctuations in the well. The Minerals Management Service (MMS) regulations consider SCP hazardous and, in principle, require its elimination. In some cases the agency may allow continuing production at a well with SCP by granting a temporary departure permit. The departure permits are based on diagnostic tests involving pressure bleed-down through a 0.5-inch needle valve followed by closing the valve and recording pressure buildup for 24 hours. Presently, analysis of testing data is mostly qualitative and limited to arbitrary criteria. This work provides theory, mathematical models and software needed for qualitative analysis of SCP tests. SCP occurs due to the loss of wells external integrity causing gas inflow from a high-pressure formation into the wells annulus. Then, the gas migrates upward through a leaking cement sheath, percolates through the mud column and accumulates above the liquid level inside the gas cap. The study identified two scenarios of gas flow in the liquid column: rapid percolation through low-viscosity Newtonian fluid; and, slow ascendance of gas bubble swarms in viscous, non-Newtonian mud. The two scenarios have been mathematically modeled and theoretically studied. The first model assumes rapid percolation and ignores gas entrainment in the liquid column. Simulation showed that early pressure buildup was controlled by mud compressibility, annular conductivity, and gas cap volume while formation pressure controlled the late pressure buildup. Mathematical simulations matched pressure buildups recorded in two wells, showing that the model had physical merit. The second mathematical model fully describes gas migration by coupling the variable rate gas flow in cement with the two-phase flow in liquid column. The model was used to study typical patterns of bleed-down and buildup from SCP diagnostic tests. It showed that analysis of pressure bleed-down gives properties of gas-liquid mixture above the cement, while a sufficiently long pressure buildup may give values of the annular conductivity, the depth and pressure of the gas-source formation.

Underbalanced drilling (UBD) has increased in recent years because of the many advantages associated with it. These include increase in the rate of penetration and reduction of lost circulation and formation damage. Drilling of deviated and horizontal wells also increased since recovery can be improved from a horizontal or a deviated well. The drilling of deviated wells using UBD method will reduce several drilling related problems such as hole cleaning and formation damage. Prediction of flow and pressure profiles while drilling underbalanced in such wells will help in designing and planning of the well. The main aim of this research is to study and model the effect of well deviation on pressure and flow profile in the drillstring and the annulus under UBD conditions through the use of mechanistic two phase flow models. Specifically, a current model is modified to include effects of wellbore deviation. Simulation results are compared with data from a deviated well drilled with UBD technology.