The Trackmaster system manufactured by Smith Services consists of a multi-ramped whipstock and a trimill assembly used to perform a sidetrack from a cased well. Smith Services has observed evidence that the trimill assembly may prematurely leave the face of the whipstock and build excess inclination and dogleg severity or may fall into the original well immediately after leaving the end of the whipstock ramp thus creating a need to predict the borehole trajectory for sidetracking operations. The goal of this project was to predict the borehole trajectory and the window profile cut in the casing by the sidetracking equipment and the curvature that would result in tubular run through the sidetracked borehole, expressed as dogleg severity. A computer program was developed that predicts the sidetrack trajectory based on the BHA analysis method proposed by Jiazhi, and extended for calculating the side force on the mills. These side forces and a logical check on the feasibility of that force within the existing well geometry were used to predict the trajectory of each mill. A method was developed to calculate and plot the paths traversed by each mill and the width of the window subsequently cut by trimill assembly moving down the face of the whipstock. Results obtained from the simulator, for selected cases of tool geometries, hole sizes and resistance to sidetracking, indicate an overall dropping tendency of the mill assembly and no tendency to prematurely leave the face of the whipstock. Therefore premature departure of the trimill assembly from the whipstock is unlikely to be caused by BHA design but may be related to some other factor such as the interaction of the mill profile with the casing wall. Further, a method was developed to calculate the radius of curvature for a specific size pipe run in the predicted trajectory for a sidetracked borehole, based on pipe diameter and wellbore geometry. The curvature was expressed as dogleg severity in degrees of inclination change per 100 ft and provides a basis for determining whether the sidetracked borehole is suitable for its intended purpose.

The search for more efficient and economical forms of energy generation is a continual process. Natural gas production and electricity generation from geopressured-geothermal aquifers is an unconventional hydrocarbon source that has long been unproductive due to its marginal economics and lack of technological certainty. This thesis demonstrates that, based on modern technological competencies and economic constraints, geopressured-geothermal energy now maintains a viable future as an alternative domestic energy source.

Downhole water sink (DWS) technology is an alternative to conventional limited-entry completions to control water production in wells with bottom water drive. DWS wells comprise two completions: the bottom completion produces water and keeps the top completion open to oil inflow. The system performance depends on careful manipulation of the top and bottom rates to maximize oil productivity and produce oil-free water from the bottom completion. Conventional nodal analysis cannot provide a solution for DWS wells because the critical rates for water coning change with water drainage rate. A reservoir simulator is used to model two-phase flow to the dual completions. Suites of related simulations are created and managed using algorithms to generate inflow performance relationships and build accompanying tubing performance models. A nodal analysis approach for dual completed wells is proposed. The approach identifies the operational range of top and bottom rates with water coning at the top completion and oil-free water production at the bottom completion subject to a range of practical operational constraints such as maximum drawdown. Because the operational range changes in time, optimization methods must evaluate the dynamic performance and maximize the well's discounted revenue by appropriately scheduling the best top and bottom production rates. New successive nodal analysis and stepwise optimization methods evaluate the best performance for a given moment and time increment. This localized strategy is compared with two algorithms that optimize the entire production schedule globally rather than sequentially - a conjugate gradient method (CGM) and a hybrid CGM-polytope method. Operating strategy can be optimized to maximize oil production early in wells' life using water drainage. Hybrid optimization (global search) finds the best solutions, but demands considerable computation. Stepwise (localized) optimization technique perform nearly as well for rate scheduling, final recovery, well life, and cumulative water production, and these methods are significantly more efficient computationally compared to the hybrid method. All the optimization methods analyzed in this study (static, stepwise, and global strategies) suggest that better well productivity can be achieved by maintaining low water saturation around the producing completion with DWS completions.

The recent push into deepwater is currently limited by high drilling costs resulting from conventional well designs. As a result, dual gradient drilling methods have been proposed. This research investigates riser gas-lift as a potential means to implement a dual gradient system. A primary concern is well control in a system containing so many different density fluids and different flow paths. The specific concerns addressed in this study were kick detection, cessation of formation feed-in, removal of kick fluids, and re-establishing hydrostatic control with a constant bottom hole pressure method. These concerns were studied using a transient, multiphase simulator whose validity was confirmed with comparison to transient, multiphase flow tests in a test well. Conventional kick detection methods relying on the pit gain and return flow rate were concluded to be effective. Two alternatives for stopping formation flow were considered, a âload-upâ method of reducing the nitrogen rate versus closing a subsea BOP. BOP closure was shown to be more reliable for stopping flow and minimizing kick volume. Further, a relatively conventional approach of circulating up a gas-lifted choke line against a surface choke was compared to a dynamic approach based on reducing the nitrogen rate and to the use of a seafloor choke. It was concluded that methods using a choke were much simpler and more effective for controlling pressure than controlling the nitrogen rate. The subsea choke has an advantage over the surface choke due to faster pressure responsiveness, smaller pressure variation, and needing fewer and smaller choke adjustments.

Much of the research on wettability in the existing literature has been done using stocktank oils and at ambient conditions. The main objective of this study is therefore to examine the validity of ambient measurements in inferring in-situ reservoir wettability. For this purpose, Drop-Shape-Analysis for interfacial tension and Dual-Drop-Dual-Crystal (DDDC) contact angle measurements have been carried out using dolomite rock, Yates reservoir stocktank and live crude oils and Yates synthetic brine at Yates reservoir conditions of 82oF and 700 psi. Two types of surfactants (nonionic and anionic) in varying concentrations have been used to study the effect of surfactants on wettability alteration in Yates reservoir. Dynamic behavior of interfacial tension (IFT) of crude oil - brine are mainly caused by the polar components or surfactants in the liquids. The oil composition especially light ends, and brine composition also have effect on it. A four-staged model was adapted from the literature to explain this time-dependent behavior of IFT. An advancing contact angle of 156o measured for dolomite rock, Yates stocktank oil and Yates synthetic brine in the absence of surfactants showed the strongly oil-wet nature. Experiments with Yates live crude oil at reservoir conditions indicated weakly water-wet behavior with a water-advancing angle of 55o For oil-wet stocktank oil system, the anionic surfactant was able to alter wettability from strongly oil-wet (156o) to less oil-wet (135o). No significant wettability alterations were observed with the nonionic surfactant in the stocktank oil containing system. However, for water-wet live oil system, the nonionic surfactant injection altered the wettability to intermediate-wet and the anionic surfactant altered it into strong oil-wet. The oil-wet behavior observed with Yates live oil due to anionic surfactant indicates the ability to this surfactant to form continuous oil-wet paths for mixed-wettability development. These experiments clearly indicate the need to use live crude oils at reservoir conditions for in-situ reservoir wettability determination. Furthermore, these experiments provided clear evidence that the surfactants used altered wettability to either intermediate-wet or mixed-wet, which could result in potential oil recovery enhancements in field applications.

In this study, we investigated several possible mechanisms that would give rise to the anomalous pressure behavior (early concave-up on Horner plot or upward drift on the derivative curve of the log-log plot and asymmetry between the pressure drawdown and buildup behavior) sometimes encountered in the turbidite reservoirs in GOM primarily using numerical simulation and 2-level experimental designs. We ascertained the most influential parameters to the pressure behavior and identified that multilayer commingled system and the leaky compartment model are the most probable mechanisms to cause the anomalous behavior due to layer or zone property contrast to a certain degree. Differential depletion was found to be the main reason for the asymmetry between the pressure drawdown and buildup. Distinctive drawdown and buildup pressure behavior and numerical convolution and deconvolution were tried to obtain influence functions for discriminating the two systems. The multilayered system was further investigated quantitatively by a three-layer model representing low, medium and high properties of a reservoir using a 3-level experimental design and the response surface method. The response is the shape of the derivative curve corresponding to each combination of reservoir parameters, which is represented by the coefficients of the polynomial obtained by non-linear piecewise regression. Significant influential reservoir parameters were identified by their influence upon the shape of derivative curves when their value changed. In addition, if we have the actual pressure data obtained from well testing, we can obtain parameter value estimates by matching the derivative curve plotted from actual pressure data using the response surface models (only contains significant factors) that describe the relationship between the derivative curve shape and the factors. We may need correlate with other data source such as well logging data to verify the parameter estimates.

The work contained in this thesis combines two previous enhanced gas recovery techniques; coproduction of water and gas from water-drive reservoirs and waterflooding of low pressure gas reservoirs. These two techniques allow the control of reservoir pressure and sweep efficiency through planed production or injection of water. A recovery optimization method, which is applicable to any gas reservoir, was developed using the concept of pressure and displacement management (PDM). Two simulation studies were conducted, using Eclipse©, to investigate recovery optimization by coproduction and waterflooding. From the coproduction study it was determined that the water production rate needed to optimize recovery increases over time, and that accelerating production rate causes the optimum coproduction rate to increase even faster over time. In the case of the waterflooding study it was concluded that the injection rate necessary to obtain a given recovery factor in a given amount of time, with a limited injection volume goes up significantly over time, and that beginning water injection early in the life of a reservoir can have several advantages to performing a waterflood near abandonment. In addition, a PDM computer model, that can be used for recovery analysis was developed for Excel. Although this application could be adapted to other programs, Excel allows for fast and effective screening of reservoirs amenable to PDM. Two field cases are analyzed in order to demonstrate the idea of recovery optimization and the versatility of the PDM application.

This research explores the characterization of petrophysical parameters such as cementation exponent, saturation exponent and effective porosity as a function of cations exchange capacity (CEC), and its impact on shaly sand interpretation. Experimental and field data were used in the study. The latest LSU model for shaly sand interpretation uses of two cementation exponents, mf and mc, to represent the tortuosity of electric current path in free water and clay bound water, respectively. Experimental measurements on three types of rock, clean sand, shaly sand and pure shale using different brine salinity, were conducted to validate the use of these two cementation exponents. The results showed that using two cementation exponents determined from representative clean sand and pure shale to characterized electrical behavior in shaly sand are substantially better than using just one cementation exponent determined from shaly sand itself. Using the same experimental results a correlation between saturation exponent value (n) and CEC as a function of brine salinity was also developed. Also a brine salinity of 15,000 ppm was found to be upper limit of low salinity range in which extra care is needed for shaly sand evaluation. Monte Carlo simulation was used to evaluate the uncertainty of water saturation calculation using LSU model with two cases: correlated input variables (formation conductivity and total porosity) and uncorrelated input variables (independent). Least square linear regression method was also used to evaluate the most significant input parameters in LSU model. This study also introduces a new simultaneous method of calculating effective porosity and cations exchange capacity (Qv) of liquid-filled reservoirs using gamma-ray, density and neutron tool responses. This method isolates the effect caused by the actual clay mineral from those of clay-sized particles in the formation. Further more, this effective porosity calculation also takes into account dry clay properties. The application of the modified LSU model in the evaluation of thinly-bedded shaly sand reservoirs is possible whenever the required criteria are met. The result was the identification of additional hydrocarbon potentials.

Significant world oil and gas reserves occur in deltaic reservoirs. Characterization of deltaic reservoirs requires understanding sedimentary and diagenetic heterogeneity at the submeter scale in three dimensions. However, deltaic facies architecture is complex and poorly understood. Moreover, precipitation of extensive calcite cement during diagenesis can modify the depositional permeability of sandstone reservoir and affect fluid flow. Heterogeneity contributes to trapping a significant portion of mobile oil in deltaic reservoirs analogous of Cretaceous Frontier Formation, Powder River Basin, Wyoming. This dissertation focuses on 3D characterization of an ancient deltaic lobe. The Turonian Wall Creek Member in central Wyoming has been selected for the present study, which integrates outcrop digitized image analysis, 2D and 3D interpreted ground penetrating radar surveys, outcrop gamma ray measurements, well logs, permeameter logs and transects, and other data for 3D reservoir characterization and flow modeling. Well log data are used to predict the geological facies using beta-Bayes method and classic multivariate statistic methods, and predictions are compared with the outcrop description. Geostatistical models are constructed for the size, orientation, and shape of the concretions using interpreted GPR, well, and outcrop data. The spatial continuity of concretions is quantified using photomosaic derived variogram analysis. Relationships among GRP attributes, well data, and outcrop data are investigated, including calcite concretion occurrence and permeability measurements from outcrop. A combination of truncated Gaussian simulation and Bayes rule predicts 3D concretion distributions. Comparisons between 2D flow simulations based on outcrop observations and an ensemble of geostatistical models indicates that the proposed approach can reproduce essential aspects of flow behavior in this system. Experimental design, analysis of variance, and flow simulations examine the effects of geological variability on breakthrough time, sweep efficiency and upscaled permeability. The proposed geostatistical and statistical methods can improve prediction of flow behavior even if conditioning data are sparse and radar data are noisy. The derived geostatistical models of stratigraphy, facies and diagenesis are appropriate for analogous deltaic reservoirs. Furthermore, the results can guide data acquisition, improve performance prediction, and help to upscale models.

Asset development teams may adjust simulation model parameters using experimental design to reveal which factors have the greatest impact on the reservoir performance. Response surfaces and experimental design make sensitivity analysis less expensive and more accurate, helping to optimize recovery under geological and economical uncertainties. In this thesis, experimental designs including orthogonal arrays, factorial designs, Latin hypercubes and Hammersley sequences are compared and analyzed. These methods are demonstrated for a gas well with water coning problem to illustrate the efficiency of orthogonal arrays. Eleven geologic factors are varied while optimizing three engineering factors (total of fourteen factors). The objective is to optimize completion length, tubing head pressure, and tubing diameter for a partially penetrating well with uncertain reservoir properties. A nearly orthogonal array was specified with three levels for eight factors and four levels for the remaining six geologic and engineering factors. This design requires only 36 simulations compared to (26,873,856) runs for a full factorial design. Hyperkriging surfaces are an alternative model form for large numbers. Hyperkriging uses the maximum likelihood variogram model parameters to minimize prediction errors. Kriging is compared to conventional polynomial response models. The robustness of the response surfaces generated by kriging and polynomial regression are compared using jackknifing and bootstrapping. Sensitivity analysis and uncertainty analysis can be performed inexpensively and efficiently using response surfaces. The proposed design approach requires fewer simulations and provides accurate response models, efficient optimization, and flexible sensitivity and uncertainty assessment.