Thesis (Ph. D.)--University of Tulsa, 1980. / Vita. Includes bibliographical references (leaves 103-107).

West Delta Block 84 Field is located off the coast of Plaquemines Parish, Louisiana. The intent of this endeavor is to prove that the two of the reservoirs, the KE-1 and KF-1, form a single communicating reservoir, the KEKF-R1; that a waterflood into the KF-1 reservoir was ineffective; that oil reserves were bypassed; and that a portion of these bypassed oil reserves can be recovered without drilling new wells. Comparisons between pre-seismic and post-seismic geological interpretations were studied, a thorough volumetric analysis was performed with a subsequent material balance calculations and a reservoir computer simulation was performed. Once a history match was made, prediction studies were performed for both remaining primary reserves and for secondary reserves recoverable through a new water-flood design and implementation. There are many new insights on this reservoir as a result of this study. First, the KE-1 and the KF-1 reservoirs are indeed one communicating reservoir. The KF-1 waterflood was inefficient and resulted in bypassed oil pay. Bypassed oil may be recovered through several techniques. Based on prediction runs on BOAST, the best case scenario analyzed thus far without additional drilling is an additional 1,600,000 barrels of oil. This study indicates that a small amount of old technology, in the form of a resurrection of a waterflood and a small amount of new technology, in the form of the "Downhole Water Sink" (DWS) method will greatly increase the ultimate recovery of the lost reserves. This study has provided sufficient evidence and documentation to justify the need for additional research and study of this reservoir. More detailed recovery strategies should be prepared, the DWS technology should be studied in more detail and a more detailed grid should be prepared for the reservoir.

Researchers at Louisiana State University, LSU, have introduced several petrophysical models expressing the electric properties of shaly sands. These models, to be used for hydrocarbon detection, are based on the Waxman and Smits concept of supplementing the water conductivity with a clay counterions conductivity. The LSU models also utilize the Dual Water theory, which relates each conductivity term to a particular type of water, free and bound, each occupying a specific volume of the total pore space. The main difference between these models and the other shaly sand models is that the counterion conductivity is represented by a hypothetical sodium chloride electrolyte. This study introduces a modified version of early LSU models. This modified model eliminates a questionable assumption incorporated in all previous shaly sand models. Previous models use same formation resistivity factor for all terms in the model. The proposed model considers that the electric current follows the effective porosity path in the term representing the free electrolyte and follows the clay porosity path in the term representing bound water. The differentiation between the two paths is accomplished by using two different formation factors one in the free water and another in the bound water term of the model. It also used two different cementation exponents to express formation factors in terms of porosity. The validity of the new model was checked using cation exchange capacities measured on core samples and drill cuttings. Calculated cation exchange capacities display good agreement with the measured cation exchange capacities. The water saturation calculated using the new model are more representative of hydrocarbon potential of the zones of interest. In addition, cation exchange capacity calculated using this modified model and log data acquired during drilling has shown potential for diagnosis of pending bit balling of PDC bits drilled with water based mud in overpressured shale.

This research utilizes reservoir data from an oilfield in Indonesia, which is characterized by shaly sand and low salinity formation water. Both low salinity and shaliness reduce the resistivity contrast between oil and water. The aim of this research was to build a comprehensive interpretation algorithm to evaluate the shaly-sand reservoir in a low salinity formation water using limited well log data. Shaly-sand interpretation is still evolving with numerous researchers conducting investigations of the clay minerals effect on rock conductivity through theoretical and experimental approach. These investigations can be loosely divided into either Fractional Shale Volume models or the Cation Exchange Capacity (clay-type) models. This research emphasizes the Cation Exchange Capacity models. Cation Exchange Capacity (CEC) is essentially a reflection of the specific surface area of clay minerals, which causes additional conductivity in shaly-sands. The modified Silva-Bassiouni model was used to interpret shaly sand formations. This model is based on the dual water concept, however it considers that the counter-ion conductivity can be represented by an equivalent sodium chloride solution. Therefore, this method eliminates the requirement for actual CEC measurements from cores. The Shale Volume based Simandoux and Indonesia models were used for comparison. The results from the Archie clean sand model were also discussed. The model was evaluated using actual production and well test data. The modified Silva-Bassiouni model was found to yield superior estimates of cation exchange capacity and fluid saturations in the reservoirs.

This study measured the liquid fallback during simulated blowout conditions. The purpose of the study was to establish a basis for developing a procedure for controlling blowouts that relies on the accumulation of liquid kill fluid injected while the well continues to flow. The results from experiments performed with air, water, 10.5 ppg and 12.0 ppg mud in an experimental 48 ft flow loop at 0°, 20°, 40°, 60° and 75° deviation angles from the vertical, as well as results from full-scale experiments performed with natural gas and water based drilling fluid in a vertical 2787-foot deep research well, are presented. The results show that the critical velocity that prevents control fluid accumulation can be predicted by Turner's model of terminal velocity based on the liquid droplet theory by also considering the flow regime of the continuous phase when evaluating the drag coefficient, and the angle of deviation from the vertical. Similarly, the amount of liquid that flows countercurrent into and accumulates in the well can be predicted based on the concept of zero net liquid flow (ZNLF) holdup. Finally all these concepts are integrated in the dynamic kill procedure, which is based on system performance analysis to better predict the feasibility of an off-bottom dynamic kill.

Approximately 2.5 billion dollars is spent annually to solve the problem of produced water in oil and gas wells. Downhole Water Sink (DWS) technology is one industry solution to control water coning in oil wells. DWS technology involves the segregated production of oil and water through separate completions with zonal isolation packer. However, several problems have been experienced in the application of the technology in watered-out oil wells. This study identified two factors that could aid in a better modeling of the technology in old vertical wells inclusion of capillary transition pressures and relative permeability hysteresis. It also identified a pressure enhanced capillary transition zone enlargement around the wellbore as responsible for the concurrent production of contaminated fluid from both completions. Another widely recommended industry solution to the problem of produced water is horizontal well technology. However, field reports indicates that water breakthrough into horizontal wells could be quite dramatic and tend to erode the merit of high deliverability. This study analyzed the problem of water cresting in horizontal wells and developed a generalized compound friction pressure loss relation for horizontal wells and pipes. The new relation includes factors such as perforations, oil-water emulsions, and radial influx of fluid into the wellbore as well as phase inversion. It also shows the results of the application of this relation in the modeling of water cresting in horizontal wells subject to bottom water drive. These results reveal an asymmetrical distribution of water influx skewed toward the heel in line with field observations. Finally, the study presents two innovative dual-completion concepts for controlling water cresting in horizontal wells adapting the principles of the Downhole Water Sink technology. The results of the initial studies shows that oil recovery could be improved by as much as 7 percent over conventional horizontal wells.

Dimensionless space provides a tool for analyzing the behavior of complex systems described by mathematical relationships. The limited application of dimensionless variables in numerical reservoir simulation and experimental design motivated the development of a complete set of dimensionless scaling groups. Inspectional analysis yielded 8 dimensionless groups completely describing the flow system. Further analysis of fluid interaction reduced the number of dimensionless groups to 7. The newly developed dimensionless equations and groups were used for analytical and numerical reservoir characterization, quantifying the behavior of differential and difference equations employed in fluid flow in three-dimensional porous media. The behavior of the dimensionless scaling is demonstrated for breakthrough time in an immiscible displacement in three dimensions. Numerical simulations were designed in dimensionless space and converted to dimensional space using several approaches. The resulting estimates of stability limits, numerical dispersion, and regime boundaries were in excellent agreement. The application of the dimensionless groups to upscaling was investigated using designed reservoir simulations to estimate dimensionless regions corresponding to different flow regimes. Analytical development, simulation runs and literature data were in good agreement. This application demonstrates the potential benefits of the proposed dimensionless groups for upscaling, sensitivity analysis, stability analysis, and reservoir characterization.

Safety culture relating to offshore operations has shifted since the Deepwater Horizon blowout and resulting oil spill. This incident has prompted the research of high volume spills during all stages of hydrocarbon exploration and production. This study particularly covers the interactions of wells and offshore networks as they pertain to situations where a release of reservoir fluids to the environment is occurring. Primary concerns of this investigation are stream confluences, leak modeling, and fluid behavior; the first two will be handled with various numerical software packages (OLGA®, CFD, and nodal analyses) while the later will require more rigorous treatment and a combination of these tools with dedicated phase behavior software (such as PVTsim®). This research will combine with risk analysis work being done by others to identify high-priority system failure scenarios. The focus in modeling high-volume leaks thus far has been placed upon reservoir properties, geology and modeling the most uncertain things when this research shows that the most influential variables for particular reservoirs lie within the flow path. When operating offshore, wells connect to subsea manifolds or other junctions to form unforeseen mixtures of crude oils; these combined fluids dictate the outcome of potentially devastating releases offshore. Flow rates through chokes have been modeled using only a few parameters, namely the pressure, choke size and the gas-liquid ratio (GLR). The leak considered herein will choke flow and create a back pressure, which will control how fluids move from the reservoir to wellhead. A properly tuned equation of state can predict the GLR fairly well, but falls short when attempting to combine the GLR of two or more fluids. A correlation is proposed to allow for more accurate leak models when only simple fluid properties are known, such as the heptanes-plus fraction.

Transporting drilled cuttings from the bottomhole to the surface becomes more difficult and problematic in highly deviated wells than in vertical wells. Cuttings tend to settle down on the low side of the annulus typically in the form of a bed which can cause further problems. The height of this bed depends on many parameters such as annular domain geometry, drilling fluid density and rheology, annular flow rate, drill pipe rotation speed, cuttings size, shape, and their density. Prediction of the stationary cuttings bed height with respect to these aforementioned parameters is thus necessary to optimize the range of the controllable parameters for a desired level of wellbore cleaning. A computational setup that represents the spatial geometry of the cuttings transport domain, and utilizes discrete phase model coupled with numerical solution of the Navier-Stokes equations augmented by a turbulence closure model SST version of k-ω is used for predicting the bed height of the stationary cuttings bed and moving cuttings velocities. Discrete phase model is a mathematical tool to navigate large number of particles in a flow field by calculating the particle paths in a Lagrangian frame by the time integration of force balance on each individual particle. Turbulence effects on the particle motion are also incorporated through a random walk model. The drag force on non-spherical particles is incorporated using a sphericity based correlation. Roughness of stationary bed surface is also incorporated through the modified law-of-the wall model. A snapshot technique is applied here in these simulations by computing flow solutions in the geometric domains with pre-defined stationary bed heights. The statistics of particle - wall collisions are analyzed over these geometrically pre-defined stationary bed surfaces to predict which domain would represent the equilibrium cuttings bed height. A systematic validation study is presented by comparing the simulation results against published experimental datasets for velocity profile estimation of non-Newtonian fluids flowing in turbulent regime, stationary bed heights, and moving bed velocities. Further, a parametric study is presented for the effects of wellbore inclination, fluid density and rheology, particle size and sphericity, inner pipe rotation and the inner pipe rotation speed.

In todays exploration and production environment it is required that engineers must collect and use vast amounts of data for flow model construction and calibra- tion, as well as reservoir estimation and optimization. With modern technology, the data volume can be overwhelming. It is necessary that data monitoring and calibration are highly efficient. It is also essential that physical and mathematical models can be tested in repeatable, inexpensive experiments. The experiments described in this thesis will develop and perform verification of algorithms and can generate prior geomodels, collect and process seismic refraction data, collect and process production data, and calibrate these models. The experimental components discussed here are collectively referred to as The Sand Tank Experiment. Contained in the LSU WaveCIS tank is a wedge shaped sand pack that can be saturated with water. Water can then be produced from this model reservoir while it is monitored by pressure/temperature sensors. A 20 kHz seismic source and 8 accelerometers are used to collect seismic first arrival data during this production period. This data can then be used to image varying water saturations throughout the reservoir. Those water saturations modify the compressional, p-wave, seismic velocities as described in the Biot and Gassman relationships. Picking first arrival times for each run of the experiment can further enhance the use of the seismic data. These first arrival times can then be compared to calculated first arrival times from simulation data and the residuals can be used to measure the accuracy.