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.

Carbon dioxide injection has currently become a major gas injection process for improved oil recovery. Laboratory evaluations of gas-oil miscibility conditions play an important role in process design and economic success of field miscible gas injection projects. Hence, this study involves the measurement and modeling of fluid-fluid miscibility in multicomponent hydrocarbon systems. A promising new vanishing interfacial tension (VIT) experimental technique has been further explored to determine fluid-fluid miscibility. Interfacial tension measurements have been carried out in three different fluid systems of known phase behavior characteristics using pendent drop shape analysis and capillary rise techniques. The quantities of fluids in the feed mixture have been varied during the experiments to investigate the compositional dependence of fluid-fluid miscibility. The miscibility conditions determined from the VIT technique agreed well with the reported miscibilities for all the three standard fluid systems used. This confirmed the sound conceptual basis of VIT technique for accurate, quick and cost-effective determination of fluid-fluid miscibility. As the fluid phases approached equilibrium, interfacial tension was unaffected by gas-oil ratio in the feed, indicating the compositional path independence of miscibility. Interfacial tension was found to correlate well with solubility in multicomponent hydrocarbon systems. The experiments as well as the use of existing computational models (equations of state and Parachor) indicated the importance of counter-directional mass transfer effects (combined vaporizing and condensing mass transfer mechanims) in fluid-fluid miscibility determination. A new mechanistic Parachor model has been developed to model dynamic gas-oil miscibility and to determine the governing mass transfer mechanism responsible for miscibility development in multicomponent hydrocarbon systems. The proposed model has been validated to predict dynamic gas-oil miscibility in several crude oil-gas systems. This study has related various types of developed miscibility in gas injection field projects with gas-oil interfacial tension and identified the multitude of roles played by interfacial tension in fluid-fluid phase equilibria. Thus, the significant contributions of this study are further validation of a new measurement technique and development of a new computational model for gas-oil interfacial tension and miscibility determination, both of which will have an impact in the optimization of field miscible gas injection projects.

The ability of an abrasive assisted water jet to cut through rocks and metals has potential applications in the oilfield. However, the size of cutting nozzle has not allowed water jet to be used on commercial scale for drilling reservoir rocks down-hole. Inefficient momentum transfer to abrasive particles from pressurized water and lack of abrasive feed rate control in commercially available units has further discouraged the use of water jet in oil industry. Despite various technical difficulties, immense power of water jet cannot be neglected. Studies have shown that momentum transfer can be improved significantly, if abrasive particles are introduced upstream of the nozzle. Limited techniques are available where abrasives are first suspended in a fluid stream and are then introduced in high-pressure water stream upstream of the nozzle. However, control over abrasive feed rate was lacking in past studies. In this investigation, an experimental apparatus was assembled a polymer solution was injected upstream of the nozzle. Injection rate was controlled, by varying the rpm of the plunger pump. The apparatus was used to study the effect of Xanthan and Polyacrylamide on water jet coherency. It is shown that addition of polymer leads to a focused water jet for a longer distance before it starts disintegrating into a mist. Furthermore, there is an optimum concentration of polymer at which the jet stays focused for the longest distance.

Natural gas hydrates are thought to be the future hydrocarbon source of the energy hungry world. Tremendous amount of research has been done to investigate the feasibility of gas production from the hydrate formations. In this direction, three basic production methods, thermal stimulation, depressurization and thermodynamic inhibitor injection have been proposed to produce hydrocarbons off the hydrates. On the other hand, they present high potential risk of drilling hazards, such as severe gasification of drilling fluid, casing collapse due to increase in pressure after dissociation of hydrate zone, and instability of ocean floor, which may cause a platform failure. Scientists and engineers have done very valuable research to understand the phase behavior of hydrates and to prevent hydrate formation throughout the well system during drilling. Reliable hydrate inhibitors have been developed for drilling and production activities. Common practice for the drilling industry has been avoidance of hydrate formations by either abandoning the project or drilling expensive directional wells to reach the target zones for many years. The goal of this project was to quantify the significance of potential problems to allow operational methods and well design to be adopted to minimize the impact of hydrate zone on drilling operations for Eastern Black Sea Offshore Exploration Project. Investigating the existing hydrate dissociation models and adopting a model to predict the amount of dissociated gas was the first step. Further steps were investigation of temperature distribution throughout the well using a thermal simulator and prediction of heat influx from the drilling fluid into the hydrate zone. In this study, hydrate dissociation mechanisms are described. Drilling and production hazards associated with dissociation are stated. For the investigation of hydrate stability/instability, well bore temperature distribution in the near well bore is determined. Hydrate dissociation rate is calculated, and results are evaluated for further changes in drilling program and well design parameters. Results obtained from the dissociation calculations were applied to a set of data from two wells drilled by ARCO/Turkish Petroleum Corporation Joint Venture in Western Black Sea, and were used to design the prospective Eastern Black Sea Offshore Exploration wells.

Feasibility of drilling with supercritical carbon dioxide to serve the needs of deep underbalanced drilling operations has been analyzed. A case study involving underbalanced drilling to access a depleted gas reservoir is used to illustrate the need for such a research. For this well, nitrogen was initially considered as the drilling fluid. Dry nitrogen, due to its low density, was unable to generate sufficient torque in the downhole motor. The mixture of nitrogen and water, stabilized as foam generated sufficient torque but made it difficult to maintain underbalanced conditions. This diminished the intended benefit of using nitrogen as the drilling fluid. CO₂ is expected to be supercritical at downhole pressure and temperature conditions, with density similar to that of a liquid and viscosity comparable to a gas. A computational model was developed to calculate the variation of density and viscosity in the tubing and the annulus with pressure, temperature and depth. A circulation model was developed to calculate the frictional pressure losses in the tubing and the annulus, and important parameters such as the jet impact force and the cuttings transport ratio. An attempt was made to model the temperatures in the well using an analytical model. Corrosion aspects of a CO₂ based drilling system are critical and were addressed in this study. The results show that the unique properties of CO₂, which is supercritical in the tubing and changes to vapor phase in the annulus, are advantageous in its role as a drilling fluid. It has the necessary density in the tubing to turn the downhole motor and the necessary density and viscosity to maintain underbalanced conditions in the annulus. The role of a surface choke is crucial in controlling the annular pressures for this system. A carefully designed corrosion control program is essential for such a system. Results of this study may also be important for understanding the flow behavior of CO₂ in CO₂ sequestration and CO₂ based enhanced oil recovery operations.

Currently, the Water-Alternating-Gas (WAG) process is the most widely practiced horizontal mode gas injection process in the industry. Although this process is conceptually sound, it has resulted in low (5 10%) oil field recoveries. Conversely, the gravity stable mode of gas injection has carved its niche as one of the most effective methods of gas injection EOR in the dipping reservoirs and pinnacle reefs. The Gas Assisted Gravity Drainage (GAGD) process is therefore being developed at LSU to extend these highly successful gravity stable applications to horizontal type reservoirs. The dissertation attempts to address six key questions: (i) do we continue to fix the problems of gravity segregation in the horizontal gas floods or find an effective alternative?, (ii) is there a happy-medium between single-slug and WAG processes that would outperform both?, (iii) what are the controlling multiphase mechanisms and fluid dynamics in gravity drainage processes?, (iv) what are the mechanistic issues relating to gravity drainage?, and (v) how can we model the novel GAGD process using traditional analytical and empirical theories and (vi) what are the roles of the classical displacement, versus drainage in the GAGD process? The original contributions of this work to the existing literature are summarized as: (i) first demonstration of the GAGD concept through high pressure experimentation, (ii) experimental demonstration of the superior oil recovery performance of the GAGD process in secondary (immiscible recovery range: 62.3% to 88.56% ROIP) and tertiary (immiscible recovery range: 47.3% to 78.9% ROIP) processes, in both miscible (avg. secondary and tertiary miscible recoveries: near 100% ROIP) and immiscible modes, and in varying wettability and rock types, (iii) experimental verification of the hypothesis that the GAGD process is largely immune to the deteriorating effects of reservoir heterogeneity and that the presence of vertical fractures possibly aid the GAGD oil recoveries, (iv) experimental demonstration of the possibility of premature gas breakthrough does not mean end of the GAGD flood, (v) preliminary mechanistic and dynamic differences between the drainage and displacement phenomenon have been identified and a new mechanism to characterize the GAGD process fluid mechanics has also been proposed.

The improvement or increase of oil recoverable from discovered reservoirs has always been a very important issue as this helps to meet ever growing energy demand. Several methods have been put forward as means of achieving this objective. Chemical flooding, using surfactants has been considered in enhanced oil recovery processes. Surfactants are used primarily to lower oil-water interfacial tension (IFT) and thus improve production. However, surfactants possess the ability to alter rock wettability and hence increase oil production. Previous investigations were performed at ambient conditions using stocktank oil. Extrapolation of the findings from the ambient conditions testing to reservoir conditions may be erroneous. Thus, reservoir condition investigations have been carried out using Yates live crude oils and Yates synthetic brine. Several coreflood experiments have been conducted at live reservoir conditions using two types of surfactants (anionic and nonionic) in varying concentrations. A core flood simulator based on JBN technique has been used to calculate oil-water relative permeabilities by history matching recovery and pressure drop measured during the corefloods. The simulated relative permeabilities have been used to infer wettability alteration based on Craigs rule of thumb to characterize wettability. The contact angle measurements, from previous investigations conducted at LSU, have been used to compare wettability alterations inferred from relative permeabilities. Furthermore, this study includes imbibition experiments as another means to infer wettability alterations by surfactants. Initial wettability has been established for the Yates field using the Amotts wettability index and changes in the wettability indices with varying surfactant concentration have also been measured. These changes have been interpreted to infer wettability alteration. The use of nonionic ethoxy alcohol surfactant at different concentrations with Yates live crude oil in corefloods experiments showed significantly higher oil recoveries indicating that the surfactant has altered wettability. The optimum surfactant concentration has been established at 1500 ppm. Other experiments conducted using the anionic ethoxy sulphate surfactant have not shown a favorable wettability alteration as Yates core was altered from weakly water-wet to weakly oil wet consequently lowering oil recoveries. Analysis of the experimental results in terms of capillary number for the live oil floods at reservoir conditions demonstrated the significance of including measured water-advancing contact angle in definition of the capillary number. The ambient imbibition tests and reservoir condition coreflow experiments conducted in this study have provided an insight into effect of surfactants on wettability alteration at both ambient and reservoir conditions using stocktank oil and live reservoir fluids and the improvement in oil recoveries as a result of wettability alteration.