Mechanistic modeling of an underbalanced drilling operation using carbon dioxide has been developed in this research. The use of carbon dioxide in an underbalanced drilling operation eliminates some of the operational difficulties that arises with gaseous drilling fluids, such as generating enough torque to run a downhole motor. The unique properties of CO₂, both inside the drill pipe and in the annulus are shown in terms of optimizing the drilling operation by achieving a low bottomhole pressure window. Typically CO₂ becomes supercritical inside the drill pipe at this high density; it will generate enough torque to run a downhole motor. As the fluid exits the drill bit it will vaporize and become a gas, hence achieving the required low density that may be required for underbalanced drilling. The latest CO₂ equation of state to calculate the required thermodynamic fluid properties is used. In addition, a heat transfer model taking into account varying properties of both pressure and temperature has been developed. A marching algorithm procedure is developed to calculate the circulating fluid pressure and temperature, taking into account the varying parameters. Both single phase CO₂ and a mixture of CO₂ and water have been studied to show the effect of produced water on corrosion rates. The model also is capable of handling different drill pipe and annular geometries.

This study addresses oil bypassing caused by water invasion to wells in edge and bottom water-drive oil reservoirs a significant problem worldwide. It is shown that the amount of by-passed (not recovered) oil is significant and could be predicted analytically and reduced by modifying wells completion. A large statistical sample from the population of possible reservoir-well systems with edge and bottom-water has been created theoretically using several databases of actual reservoirs properties worldwide. Dimensional analysis allowed converting reservoir properties distributions into dimensionless group distributions. Then, the amount of by-passed oil was correlated with the dimensionless groups using designed experiments conducted on a reservoir simulator. The resulting correlations determine the percent amount of movable oil that could be recovered by the end of wells operation, when the water cut value reaches its maximum limit. They also show how operational parameters such as well spacing, penetration and production rate may affect oil recovery. From the sensitivity analysis, the end-point mobility ratio appears to control more than 55 percent of the oil bypassing process far more than other groups. The statistical results also show that half of the typical edge and bottom-water well-reservoir systems would have at least 17% or 25% of their movable oil bypassed, respectively. The effect of reservoir heterogeneity defined by permeability stratification has been studied for edge-water systems having transgressive, regressive and serrated depositional sequences with a Dykstra-Parsons coefficient of 0.75. Oil bypassing showed to be qualitatively more significant in the transgressive sequences. It was also found that the effect of reservoir heterogeneity is more significant for reservoirs with high end-point mobility ratios. Numerical reservoir simulation is also used to investigate improved recovery of wells completions of different penetration and dual-completed wells with segregated inflow from the top and bottom (water sink) completions. It appears that short completions perform best in reservoirs with large end-point mobility ratios produced at low rates by delaying water breakthrough and improving the amount of oil recovered per barrel of fluid produced. For most reservoirs with water drive, however, the results show that the best single completion strategy is the use of fully penetrating wells, since they improve the recovery rate. Dual well completions with water sink (DWS) enable independent (although synchronized) rate schedules at the two completions. This study offers a new method to operate DWS systems by using variable rates at the bottom completion for a constant production rate - with limited maximum water cut - at the top completion over the entire life of the well. The method provides better distribution of produced fluids, as it controls water saturation outside the well. When compared with conventional short completion, DWS well recovers oil faster and may also produce oil-free water for re-injection. However, a comparison with long single completion of similar length based on the same total fluid rate does not give different recovery rates but shows that DWS well operates at different pressure drawdowns and produces two streams of fluids having substantially different compositions. It is, then, concluded that the recovery performance of the two types of wells may be different if the basis for comparison is a maximum pressure drawdown rather than same total fluid rate.

Hydrocarbon resources from unconventional shale gas reservoirs are becoming very important in the United States in recent years. Understanding the effects of adsorption on production data analysis will increase the effectiveness of reservoir management in these challenging environments. The use of an adjusted system compressibility proposed by Bumb and McKee (1988) is critical in this process. It allows for dimensional and dimensionless type curves to be corrected at a reasonably fundamental level, and it breaks the effects of adsorption into something that is relatively simple to understand. This coupled with a new form of material balance time that was originally put forth by Palacio and Blasingame (1993), allows the effects of adsorption to be handled in production data analysis. The first step in this process was to show the effects of adsorption on various systems: single porosity, dual porosity, hydraulically fractured, and dual porosity with a hydraulic fracture. These systems were first viewed as constant terminal rate systems then as constant terminal pressure systems. Constant pressure systems require a correction to be made to material balance time in order to apply the correction for adsorption in the form of an adjusted total system compressibility. Next, various analysis methods were examined to test their robustness in analyzing systems that contain adsorbed gas. Continuously, Gas Production Analysis (GPA) (Cox, et al. 2002) showed itself to be more accurate and more insightful. In combination with the techniques put forth in this work, it was used to analyze two field cases provided by Devon Energy Corporation from the Barnett Shale. The effects of adsorption are reasonably consistent across the reservoir systems examined in this work. It was confirmed that adsorption can be managed and accounted for using the method put forth in this work. Also, GPA appears to be the best and most insightful analysis method tested in this work.

Gas Injection is the second largest EOR process in U.S. To increase the extent of the reservoir contacted by displacing fluids, gas and water are injected intermittently - water-alternating-gas (WAG) process, is widely practiced. This experimental study is aimed at evaluating the WAG process performance in short and long cores as a function of gas-oil miscibility and brine composition. This performance evaluation has been carried out by comparing oil recoveries between WAG injection and continuous gas injection (CGI). Miscible (2500 psi) and immiscible (500 psi) floods were conducted using Berea cores, n-Decane and two different brines, namely the commonly used 5% NaCl solution and another the multicomponent brine from the West Texas Yates reservoir. Each of the ten corefloods consisted of series of steps including brine saturation, absolute permeability determination, flooding with oil (drainage) to initial oil saturation, flooding with brine (imbibition) to residual oil saturation, and finally, tertiary gas injection to recover the waterflood residual oil. It was found that comparing tertiary gas floods only on the basis of recovery yielded misleading conclusions. However, when oil recovery per unit volume of gas injection was used as a parameter to evaluate the floods, miscible gas floods were found more effective (recovery 60-70% higher) than immiscible floods. The WAG mode of injection out-performed the CGI floods. At increased gas volume injection, the performance of miscible CGI flood, inspite of the high injection pressure, approached the immiscible floods. A change in brine composition from 5% NaCl to 9.26% multivalent Yates reservoir brine showed a slight adverse effect on tertiary gas flood recovery due to increased solubility of CO2 in the latter. While immiscible WAG floods in short cores donot show appreciable improvement over CGI immiscible floods, WAG recovery was 31% higher than 6-ft CGI floods. The results of this study prompted a new process by combining CGI and WAG modes of gas injection. Such a process was found patented and practiced in the industry. In addition to providing performance characteristics of the WAG process, this study has indicated directions for further research aimed at improving oil recovery from gas injection processes.

Although foam has been widely used in many scientific and engineering applications, the current understanding of foam rheology in pipes is still very limited because of its complex nature. This experimental study, for the first time, investigates the flow rheology of foams in pipes by placing a special emphasis on two distinct foam flow regimes. A wide range of experimental conditions are examined in this study, which include five different surfactant formulations (Cedepal FA-406, Petrostep CG-50, Stepanform 1050, Aquet TD-600, and Ultra-Palmolive), three different surfactant concentrations (0.1, 1, and 5 wt %), two different pipe diameters (0.5 and 1 inch nominal size stainless steel pipes), and two different filter opening sizes (50 and 90 micrometers) for upstream foam generation. The experiments revealed the following characteristics: (1) foam flow in pipes exhibited two different flow regimes called high-quality regime and low-quality regime, (2) the high-quality regime was characterized by unstable and oscillating pressure response which resulted from repeating free gas and foam slug, whereas the low-quality regime was characterized by stabilized pressure response which resulted from the flow of uniform and homogeneous foams, (3) different patterns of pressure contours were observed - the pressure contours were relatively steep in the high-quality regime but relatively gentle, or even almost horizontal, in the low-quality regime, (4) foam rheology in the high-quality regime was shear thickening to liquid injection velocity in all cases, and foam rheology in the low-quality regime was not consistent, and (5) the value of foam quality (fg*) that splits the two flow regimes was shown to be affected by experimental conditions such as surfactant formulations and concentrations. These observations imply that the rheology in the high-quality regime is primarily governed by dynamic mechanisms of lamella creation and coalescence during the flow, and the rheology in the low-quality regime is primarily governed by interactions between bubbles and/or interactions between bubbles and pipe wall. Therefore, the high-quality regime is likely to expand (or, the low-quality regime is likely to contract, equivalently) with a reduction in surfactant foamability. Implications of distinct foam behaviors in two flow regimes in practical applications are also discussed.

CO2 displacement is the most widely used EOR process, but poor sweep efficiency and large CO2 utilization rates are limitations to the economic and technical success of CO2 floods. Developing a methodology to maximize the sweep efficiency and minimize the CO2 utilization rate would greatly improve the economics of these fields. This thesis evaluates the sweep efficiency of a successful, late-in-life, continuous injection CO2 flood at the Little Creek Field, Mississippi. In this work, we evaluate several heterogeneity measures in terms of recovery efficiency and utilization rate. Core studies available from 41% of the wells in the field were used to compute various heterogeneity measures, and the resulting values were correlated with pattern-by-pattern recoveries and CO2 utilization rates. Weak correlation trends were found for most of the measures in terms of R2 values. However, there was still a trend confirming the idea that more heterogeneity corresponds to higher utilization rates and lower recoveries. Mapping of the well-by-well heterogeneity measures appear to show geological trends better than traditional maps of the basic parameters that make up the measures. These geological trends were then successfully used to adjust rock-types during reservoir modeling. Reservoir simulation was performed to understand the reservoir response to CO2 flooding and develop alternatives for sweep improvement. Continuous CO2 injection under certain alternate operations would help. The WAG process was effective in increasing the sweep efficiency of the reservoir for most of the cases studied by providing favorable mobility ratios and contacting more of the oil in the reservoir. The Gas-Assisted Gravity Drainage (GAGD) process was also evaluated. Solvent saturation profiles show that results are essentially consistent with the proposed GAGD theory. However, oil recovery was less than the best WAG cases, which is not surprising due to the high connate water saturation (0.56), relatively low thickness and lack of dip to the reservoir. Moreover, an increase in recovery could be realized more in the future for both the WAG and GAGD processes because CO2 contacted larger amounts of unswept oil in the reservoir compared to continuous CO2 flooding.

A reservoir engineering Grid computing toolkit, ResGrid and its extensions, were developed and applied to designed reservoir simulation studies and continuous reservoir model updating. The toolkit provides reservoir engineers with high performance computing capacity to complete their projects without requiring them to delve into Grid resource heterogeneity, security certification, or network protocols. <p align=left>Continuous and real-time reservoir model updating is an important component of closed-loop model-based reservoir management. The method must rapidly and continuously update reservoir models by assimilating production data, so that the performance predictions and the associated uncertainty are up-to-date for optimization. The ensemble Kalman filter (EnKF), a Bayesian approach for model updating, uses Monte Carlo statistics for fusing observation data with forecasts from simulations to estimate a range of plausible models. The ensemble of updated models can be used for uncertainty forecasting or optimization. <p align=left>Grid environments aggregate geographically distributed, heterogeneous resources. Their virtual architecture can handle many large parallel simulation runs, and is thus well suited to solving model-based reservoir management problems. In the study, the ResGrid workflow for Grid-based designed reservoir simulation and an adapted workflow provide tools for building prior model ensembles, task farming and execution, extracting simulator output results, implementing the EnKF, and using a web portal for invoking those scripts. <p align=left>The ResGrid workflow is demonstrated for a geostatistical study of 3-D displacements in heterogeneous reservoirs. A suite of 1920 simulations assesses the effects of geostatistical methods and model parameters. Multiple runs are simultaneously executed using parallel Grid computing. Flow response analyses indicate that efficient, widely-used sequential geostatistical simulation methods may overestimate flow response variability when compared to more rigorous but computationally costly direct methods. <p align=left>Although the EnKF has attracted great interest in reservoir engineering, some aspects of the EnKF remain poorly understood, and are explored in the dissertation. First, guidelines are offered to select data assimilation intervals. Second, an adaptive covariance inflation method is shown to be effective to stabilize the EnKF. Third, we show that simple truncation can correct negative effects of nonlinearity and non-Gaussianity as effectively as more complex and expensive reparameterization methods.

<p>Reservoir architecture may be inferred from analogs and geologic concepts, seismic surveys, and well data. Stochastically inverted seismic data are uninformative about meter-scale features, but aid downscaling by constraining coarse-scale interval properties such as total thickness and average porosity. Well data reveal detailed facies and vertical trends (and may indicate lateral trends), but cannot specify intrawell stratal geometry. Consistent geomodels can be generated for flow simulation by systematically considering the precision and density of different data. Because seismic inversion, conceptual stacking, and lateral variability of the facies are uncertain, stochastic ensembles of geomodels are needed to capture variability. <p>In this research, geomodels integrate stochastic seismic inversions. At each trace, constraints represent means and variances for the inexact constraint algorithms, or can be posed as exact constraints. These models also include stratigraphy (a stacking framework from prior geomodels), well data (core and wireline logs to constrain meter-scale structure at the wells), and geostatistics (for correlated variability). These elements are combined in a Bayesian framework. <p>This geomodeling process creates prior models with plausible bedding geometries and facies successions. These prior models of stacking are updated, using well and seismic data to generate the posterior model. Markov Chain Monte Carlo methods sample the posteriors. Plausible subseismic features are introduced into flow models, whilst avoiding overtuning to seismic data or conceptual geologic models. Fully integrated cornerpoint flow models are created, and methods for screening and simulation studies are discussed. The updating constraints on total thickness and average porosity need not be from a seismic survey: any spatially dense estimates of these properties may be used.

The purpose of this project is to develop a pore pressure and fracture gradient prediction strategy for the Ewing Banks 910 (EW 910) area. Petrophysical and measured pressure data for eight wells previously drilled in the EW 910 area will be examined and reviewed. This strategy will help design future drilling and completion operations in the aforementioned area. Two pore pressure prediction strategies and one fracture gradient prediction strategy will be reviewed and applied to the available data. The first pore pressure prediction strategy reviewed was developed by W. R. Matthews. This strategy utilizes a geologic age specific overlay which indicates the normally pressured compaction trendline for the appropriate geologic age. After plotting the observed resistivity/conductivity data on the geologic age specific overlay, formation pore pressures can be predicted. A simple calibration of the data is required to implement this method. The second pore pressure prediction strategy reviewed was developed by Ben Eaton. Eaton developed a simple relationship that predicts the formation pore pressure knowing the normally pressured compaction trendline, the observed resistivity/conductivity data and a relationship for formation overburden stress. The fracture pressure prediction strategy reviewed was also developed by Ben Eaton. The data required for this prediction strategy is formation overburden stress, pore pressure and formation Poissons ratio. A relationship for the overburden stress and Poissons ratio can be developed or one of Eatons published relationships can be used. Ultimately, the Eaton fracture gradient prediction strategy results in a simple and accurate relationship provided an accurate estimate of pore pressure is available. The two formation pore pressure prediction strategies were applied to the petrophysical data. The resulting formation pore pressure prediction was compared to the measured pressure data obtained from the eight offset wells. After analyzing each pore pressure model against the available pressure data, the Eaton pore pressure prediction strategy was chosen as the best model to implement in future operations. The fracture gradient prediction strategy was implemented using the formation pore pressures estimated by the Eaton pore pressure prediction strategy. The fracture gradients predicted were within range of the fracture gradients suggested by the offset data.

<p>This study derives from observations made in petroleum research and practices of chemical industry that efficient mixing takes place in segregated immiscible fluid flow in granular packs and static mixers. A hypothesis was formulated that transverse mixing (TM) across oil-water interface may occur in segregated inflow to wells resulting in progressive transition zone, more water production, and reduced oil productivity. Mixing is broadly interpreted here to address the entire range of stirring, splitting, dispersion and diffusion processes between two fluids.</p> <p>Initial study showed that a commercial reservoir simulator would not model any transition zone in segregated oil-water flow at high pressure gradient as it lacks a mathematical description of the phenomenon. Initial analysis identified two major effects contributing to transverse mixing: shear mixing due to velocity contrast and momentum transfer due to tortuosity and streams collisions.</p> <p>The shear mixing effect was studied in the Hele-Shaw (H-S) flow cell, and TM of oil and water above unstable interface were observed. However, considering wavelength reduction caused by H-S model gap size corresponding to rocks pore size, the mixing zone appeared to be negligible.</p> <p>The momentum transfer (collision) effect has been studied by considering ratio of size of pore and throat. TM criterion was developed using modified Richardson number.</p> <p>Only early TM has been confirmed with granular-pack flow cell experiments due to dimensional restrictions. The results showed only water invading oil layer above the initial water/oil interface. Also, TM increased for higher pressure gradients and larger grain sizes, and reduced for more viscous oil.</p> <p>A mathematical model of early TM has been derived by solving a diffusion equation with constant flow velocity and water saturation at the initial W/O interface. The model reasonably matches experimental results thus enabling determination of the transverse dispersion coefficient, similar to miscible dispersion.</p> <p>The TM effect in wells was qualified by converting the linear TM model to radial flow model and integrating within the wells inflow zone. The results showed TM would increase water production by 2.5%, and reduce oil rate by 8.3% thus reducing wells productivity.</p> <p>Limitations and shortcoming of the study are discussed together with recommendations.</p>