Water influx and well completions affect recovery from water-drive gas reservoir. Material balance, aquifer models and well inflow equations are used to examine and predict the pressure depletion, water influx, and production rates of water-drive gas reservoirs. The parameters of these simple, lumped models are estimated from simulation results using response surfaces and experimental designs for eight varying geologic and engineering factors. Eleven simulated responses (including maximum gas rate, aquifer and well constants, and water breakthrough) are analyzed using ANOVA and response models. A sensitivity analysis of aquifer productivity index, gas production factor, and sweep efficiency reveals that permeability is the dominating factor. In contrast to earlier investigations, this study indicates that water-drive gas recovery is often higher for higher permeability water-drive gas reservoirs. The high gas mobility more than offsets the high aquifer mobility. The other seven factors are statistically significant for many responses, but much less important in determining reservoir behavior. The proposed approach combines simple analytic expressions with more complete but difficult-to-use reservoir simulation models. The response models can be used to make quick, accurate predictions of water-drive gas reservoirs that include the effects of changing geologic and engineering variables. These simple, approximate models are appropriate for prospect screening, sensitivity analysis and uncertainty analysis.

Surfactants have been considered for enhanced oil recovery by reduced oil-water interfacial tension. However, these surfactants may enhance oil recovery via wettability alteration as well. This study experimentally determines the influence of surfactant type and concentration on oil recovery, oil-water relative permeabilities and wettability in reservoir rocks. Several coreflood experiments were conducted using Yates reservoir fluids in Berea rocks and two types of surfactants (nonionic and anionic) in varying concentrations. A coreflood simulator was used to calculate oil-water relative permeabilities by history matching recovery and pressure drop measured during the corefloods. These relative permeability variations were interpreted using Craig's rules-of-thumb to characterize wettability alterations induced by the surfactants. The two main mechanisms behind the use of surfactants to enhance oil recovery are (1) reduction in interfacial tension and (2) alteration of wettability. To discern the relative contributions from these two mechanisms on enhanced oil recovery, two series of coreflood experiments have been conducted using a nonionic surfactant in varying concentrations. The first series used decane as the oil phase to quantify the effect of reduction in interfacial tension on oil recovery, while considering wettability effects in the decane-brine-Berea system to be negligible. The second series used Yates crude oil in place of decane to quantify the effects of reduction in interfacial tension as well as wettability alteration on enhanced oil recovery. The same two sets of experiments are then repeated with the anionic surfactant. The comparison of results of these four sets of experiments showed significantly higher oil recoveries for second series of experiments, indicating that the surfactants have altered wettability. The optimum surfactant concentration was found to be 3500 ppm. In three of the four cases studied, oil/water emulsions caused high pressure drops during the flooding experiments, strongly affecting the relative permeability curves. Craig's rules-of-thumb may not be applicable in systems containing emulsions. This study suggests that the development of a mixed-wettability state yields significantly higher oil recoveries observed in Yates crude oil systems. The significant contributions of this study are the quantification of the wettability altering capability of surfactants and the consequent enhancement of oil recovery.

Bit performance in deep shale when using water-based mud is typically poor. This study is part of a larger research project to improve that performance entitled "Automated Rig Controls for Improved Drilling Costs." The objective of the project is diagnosis of changes in drill bit performance to provide a logical basis for automating draw works control, maximizing bit performance, and reducing drilling costs. The specific goal of this study is a means to diagnose bit performance, specifically to identify bit balling and lithology changes, using real-time drilling data. The research began by identifying symptoms relating to specific causes of bit performance changes based on previously published research. Four published and six additional new potential parameters were identified for evaluation. Laboratory data was analyzed from both single cutter and full-scale tests to evaluate which diagnostic measures best indicated the causes of different or changing performance. Five of the diagnostic parameters were selected for further evaluation. An example set of field data was acquired that included both surface records of operational parameters and an electric log of the formations in a 2600 foot interval. Rate of penetration was estimated using Lubinski's method. Three published and two new diagnostic parameters were calculated for the entire interval. The sign, magnitude, and trend of these diagnostic parameters were compared to the changes evident in the data to establish the relationship between each diagnostic parameter, the lithology, and whether the bit was balled or drilling efficiently. As a result, a method for defining baseline values of each parameter, identifying lithology, and determining whether the severity of bit balling is constant, being reduced, or increasing is proposed and demonstrated. This method can potentially provide a basis for operational changes to improve bit performance, to help detect lithology changes, and to delineate bed boundaries more accurately.

Oil and natural gas resources in the deepwater Gulf of Mexico are important for the U.S. economy, but development is limited by high costs. Dual density drilling concepts that result in wellbore pressure gradients similar to the natural subsurface gradients can simplify well designs and reduce costs. Riser dilution may be an economical means of achieving such a system. This system would use a low density fluid to dilute the weighted wellbore fluid and give an intermediate density fluid in the riser. Two key concerns addressed in this study are whether a drilling fluid can be formulated that will suspend solids and transport cuttings after dilution and whether the fluid returning from the riser can be separated into wellbore and dilution fluids for a continuous process. The first concern was addressed by laboratory testing of synthetic-base drilling fluids. The wellbore, riser, and dilution fluids were formulated with the same synthetic fluid to water ratio and liquid phase product concentrations with only the barite concentration, and therefore density, being different. Formulations with good emulsion stability over the maximum density range needed for real deepwater applications were developed. However, appropriate rheologies for the extreme case of 17.0 ppg wellbore fluid and 9.5 ppg riser fluid were not achieved with laboratory muds. Separation testing was conducted to address the second concern using a laboratory centrifuge and hydrocyclones. The laboratory centrifuge demonstrated that practically all barite could be removed from the dilution stream and retained in a wellbore stream, but also that the wellbore stream rheologies were excessively high. Hydrocyclone results implied the need for two stages of separation. The most successful two stage trial gave less contrast in densities than the laboratory centrifuge, but gave better rheologies and emulsion stabilities than either the laboratory fluid or the laboratory centrifuge tests. Also, the rheologies from hydrocyclone testing were only slightly less than the rheology values considered necessary for a working riser dilution system. Both the density contrast and the rheologies were also close to the best centrifuge results published by others working on similar systems.

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.