Modeling Of Depressurization And Thermal Reservoir Simulation To Predict Gas Production From Methane -Hydrate Formations

Thesis (Ph.D.) University of Alaska Fairbanks, 2007Gas hydrates represent a huge potential future resource of natural gas. However, significant technical issues need to be resolved before this enormous resource can be considered to be an economically producible reserve. Developments in numerical reservoir simulations give useful information in predicting the technical and economic analysis of the hydrate-dissociation process. For this reason, a commercial reservoir simulator, CMG (Computer Modeling Group) STARS (Steam, Thermal, and Advanced Processes Reservoir Simulator) has been adapted in this study to model gas hydrate dissociation caused by several production mechanisms (depressurization, hot water injection and steam injection). Even though CMG is a commercially available simulator capable of handling thermal oil recovery processes, the novel approach of this work is the way by which the simulator was modified by formulating a kinetic and thermodynamic model to describe the hydrate decomposition. The simulator can calculate gas and water production rates from a well, and the profiles of pressure, temperature and saturation distributions in the formation for various operating conditions. Results indicate that a significant amount of gas can be produced from a hypothetical hydrate formation overlying a free gas accumulation by several different production scenarios. However, steam injection remarkably improves gas production over depressurization and hot water injection. A revised axisymmetric model for simulating gas production from hydrate decomposition in porous media by a depressurization method is also presented. Self-similar solutions are obtained for constant well pressure and fixed natural gas output. A comparison of these two boundary conditions at the well showed that a higher gas flow rate can be achieved in the long run in the case of constant well pressure over that of fixed gas output in spite of slower movement of the dissociation front. For different reservoir temperatures and various well boundary conditions, distributions of temperature and pressure profiles, as well as the gas flow rate in the hydrate zone and the gas zone, are evaluated

PRODRUGS AND DERIVATIVES OF ALPHA, BETA-UNSATURATED KETONES DESIGNED AS ANTICANCER AGENTS

In the chemotherapy of cancer, a number of different classes of drugs are used. Of these, alkylating agents constitute about 30% and while a few of the less common cancers can be effectively treated by chemotherapy or adjuvant therapy, the drugs are marked by lack of specificity and high toxicity. Moreover, the vast majority of cancers cannot be treated satisfactorily by any therapy at all. Therefore, there is a need for better and more selective anticancer drugs. The present project may be considered to consist of the following two areas. I) Design, synthesis and antineoplastic evaluation) of novel candidate antineoplastics of the type- a) Mannich bases and related compounds. b)0G,13-Unsaturated ketones and their derivatives. II) Physicochemical, stability and in vitro studies of selected compounds. The compounds were designed as alkylating agents so that they would alkylate important biomacromolecules in the rapidly proliferating cancer cells. They were, therefore, either strong alkylators per se or were designed to generate such a species in vivo

Characterization of Lubricant Droplets for Internal Minimum Quantity Lubrication

This study characterized airborne diameter and distribution of two commercially available lubricants’ droplets for internal minimum quantity lubrication (MQL). The effect of varying air pressure on the resultant droplets and drilling performance was studied. Resultant droplet sizes and contact angles on A380 aluminum were evaluated. Droplet formation at the drill tip was investigated with a high-speed camera. Drilling tests with MQL, flood coolants, and dry condition were performed to validate the effectiveness of through tool MQL. Airborne droplet diameters were highly sensitive to the coolant channel sizes. Overall, the airborne droplets of Castrol oil were larger than that of Coolube oil at different air pressures and drill sizes. Contact angle of Coolube oil is about half of that for Castrol oil. High speed imaging showed the tendency of high viscosity Castrol oil sticking to the drill tip. Built-up-edges were significant when drilling A380 aluminum with Castrol oil. Due to high machinability of A380 aluminum, the hole diameter and hole cylindricity were the same when drilling with MQL or flood coolant, excessive amount of MQL lubricant did not improve the hole quality, but without coolant the hole cylindricity doubled. The result of this study will be applied for high aspect ratio drilling of A380 aluminum engine blocks. The same procedure can be extended to study deep hole drilling of difficult-to-machine alloys and additively manufactured metals

Resource Characterization and Quantification of Natural Gas-Hydrate and Associated Free-Gas Accumulations in the Prudhoe Bay - Kuparuk River Area on the North Slope of Alaska

Natural gas hydrates have long been considered a nuisance by the petroleum industry. Hydrates have been hazards to drilling crews, with blowouts a common occurrence if not properly accounted for in drilling plans. In gas pipelines, hydrates have formed plugs if gas was not properly dehydrated. Removing these plugs has been an expensive and time-consuming process. Recently, however, due to the geologic evidence indicating that in situ hydrates could potentially be a vast energy resource of the future, research efforts have been undertaken to explore how natural gas from hydrates might be produced. This study investigates the relative permeability of methane and brine in hydrate-bearing Alaska North Slope core samples. In February 2007, core samples were taken from the Mt. Elbert site situated between the Prudhoe Bay and Kuparuk oil fields on the Alaska North Slope. Core plugs from those core samples have been used as a platform to form hydrates and perform unsteady-steady-state displacement relative permeability experiments. The absolute permeability of Mt. Elbert core samples determined by Omni Labs was also validated as part of this study. Data taken with experimental apparatuses at the University of Alaska Fairbanks, ConocoPhillips laboratories at the Bartlesville Technology Center, and at the Arctic Slope Regional Corporation's facilities in Anchorage, Alaska, provided the basis for this study. This study finds that many difficulties inhibit the ability to obtain relative permeability data in porous media-containing hydrates. Difficulties include handling unconsolidated cores during initial core preparation work, forming hydrates in the core in such a way that promotes flow of both brine and methane, and obtaining simultaneous two-phase flow of brine and methane necessary to quantify relative permeability using unsteady-steady-state displacement methods

Phase Behavior, Solid Organic Precipitation, and Mobility Characterization Studies in Support of Enhanced Heavy Oil Recovery on the Alaska North Slope

The medium-heavy oil (viscous oil) resources in the Alaska North Slope are estimated at 20 to 25 billion barrels. These oils are viscous, flow sluggishly in the formations, and are difficult to recover. Recovery of this viscous oil requires carefully designed enhanced oil recovery processes. Success of these recovery processes is critically dependent on accurate knowledge of the phase behavior and fluid properties, especially viscosity, of these oils under variety of pressure and temperature conditions. This project focused on predicting phase behavior and viscosity of viscous oils using equations of state and semi-empirical correlations. An experimental study was conducted to quantify the phase behavior and physical properties of viscous oils from the Alaska North Slope oil field. The oil samples were compositionally characterized by the simulated distillation technique. Constant composition expansion and differential liberation tests were conducted on viscous oil samples. Experiment results for phase behavior and reservoir fluid properties were used to tune the Peng-Robinson equation of state and predict the phase behavior accurately. A comprehensive literature search was carried out to compile available compositional viscosity models and their modifications, for application to heavy or viscous oils. With the help of meticulously amassed new medium-heavy oil viscosity data from experiments, a comparative study was conducted to evaluate the potential of various models. The widely used corresponding state viscosity model predictions deteriorate when applied to heavy oil systems. Hence, a semi-empirical approach (the Lindeloff model) was adopted for modeling the viscosity behavior. Based on the analysis, appropriate adjustments have been suggested: the major one is the division of the pressure-viscosity profile into three distinct regions. New modifications have improved the overall fit, including the saturated viscosities at low pressures. However, with the limited amount of geographically diverse data, it is not possible to develop a comprehensive predictive model. Based on the comprehensive phase behavior analysis of Alaska North Slope crude oil, a reservoir simulation study was carried out to evaluate the performance of a gas injection enhanced oil recovery technique for the West Sak reservoir. It was found that a definite increase in viscous oil production can be obtained by selecting the proper injectant gas and by optimizing reservoir operating parameters. A comparative analysis is provided, which helps in the decision-making process

Chemical and Microbial Characterization of North Slope Viscous Oils to Assess Viscosity Reduction and Enhanced Recovery

A large proportion of Alaska North Slope (ANS) oil exists in the form of viscous deposits, which cannot be produced entirely using conventional methods. Microbially enhanced oil recovery (MEOR) is a promising approach for improving oil recovery for viscous deposits. MEOR can be achieved using either ex situ approaches such as flooding with microbial biosurfactants or injection of exogenous surfactant-producing microbes into the reservoir, or by in situ approaches such as biostimulation of indigenous surfactant-producing microbes in the oil. Experimental work was performed to analyze the potential application of MEOR to the ANS oil fields through both ex situ and in situ approaches. A microbial formulation containing a known biosurfactant-producing strain of Bacillus licheniformis was developed in order to simulate MEOR. Coreflooding experiments were performed to simulate MEOR and quantify the incremental oil recovery. Properties like viscosity, density, and chemical composition of oil were monitored to propose a mechanism for oil recovery. The microbial formulation significantly increased incremental oil recovery, and molecular biological analyses indicated that the strain survived during the shut-in period. The indigenous microflora of ANS heavy oils was investigated to characterize the microbial communities and test for surfactant producers that are potentially useful for biostimulation. Bacteria that reduce the surface tension of aqueous media were isolated from one of the five ANS oils (Milne Point) and from rock oiled by the Exxon Valdez oil spill (EVOS), and may prove valuable for ex situ MEOR strategies. The total bacterial community composition of the six different oils was evaluated using molecular genetic tools, which revealed that each oil tested possessed a unique fingerprint indicating a diverse bacterial community and varied assemblages. Collectively we have demonstrated that there is potential for in situ and ex situ MEOR of ANS oils. Future work should focus on lab and field-scale testing of ex situ MEOR using Bacillus licheniformis as well as the biosurfactant-producing strains we have newly isolated from the Milne Point reservoir and the EVOS environment

Rural Alaska Coal Bed Methane: Application of New Technologies to Explore and Produce Energy

The Petroleum Development Laboratory, University of Alaska Fairbanks prepared this report. The US Department of Energy NETL sponsored this project through the Arctic Energy Technology Development Laboratory (AETDL) of the University of Alaska Fairbanks. The financial support of the AETDL is gratefully acknowledged. We also acknowledge the co-operation from the other investigators, including James G. Clough of the State of Alaska Department of Natural Resources, Division of Geological and Geophysical Surveys; Art Clark, Charles Barker and Ed Weeks of the USGS; Beth Mclean and Robert Fisk of the Bureau of Land Management. James Ferguson and David Ogbe carried out the pre-drilling economic analysis, and Doug Reynolds conducted post drilling economic analysis. We also acknowledge the support received from Eric Opstad of Elko International, LLC; Anchorage, Alaska who provided a comprehensive AFE (Authorization for Expenditure) for pilot well drilling and completion at Fort Yukon. This report was prepared by David Ogbe, Shirish Patil, Doug Reynolds, and Santanu Khataniar of the University of Alaska Fairbanks, and James Clough of the Alaska Division of Geological and Geophysical Survey. The following research assistants, Kanhaiyalal Patel, Amy Rodman, and Michael Olaniran worked on this project

RESOURCE CHARACTERIZATION AND QUANTIFICATION OF NATURAL GAS-HYDRATE AND ASSOCIATED FREE-GAS ACCUMULATIONS IN THE PRUDHOE BAY - KUPARUK RIVER AREA ON THE NORTH SLOPE OF ALASKA

Interim results are presented from the project designed to characterize, quantify, and determine the commercial feasibility of Alaska North Slope (ANS) gas-hydrate and associated free-gas resources in the Prudhoe Bay Unit (PBU), Kuparuk River Unit (KRU), and Milne Point Unit (MPU) areas. This collaborative research will provide practical input to reservoir and economic models, determine the technical feasibility of gas hydrate production, and influence future exploration and field extension of this potential ANS resource. The large magnitude of unconventional in-place gas (40-100 TCF) and conventional ANS gas commercialization evaluation creates industry-DOE alignment to assess this potential resource. This region uniquely combines known gas hydrate presence and existing production infrastructure. Many technical, economical, environmental, and safety issues require resolution before enabling gas hydrate commercial production. Gas hydrate energy resource potential has been studied for nearly three decades. However, this knowledge has not been applied to practical ANS gas hydrate resource development. ANS gas hydrate and associated free gas reservoirs are being studied to determine reservoir extent, stratigraphy, structure, continuity, quality, variability, and geophysical and petrophysical property distribution. Phase 1 will characterize reservoirs, lead to recoverable reserve and commercial potential estimates, and define procedures for gas hydrate drilling, data acquisition, completion, and production. Phases 2 and 3 will integrate well, core, log, and long-term production test data from additional wells, if justified by results from prior phases. The project could lead to future ANS gas hydrate pilot development. This project will help solve technical and economic issues to enable government and industry to make informed decisions regarding future commercialization of unconventional gas-hydrate resources

Sonochemical Formation of Peracetic Acid in Batch Reactor: Process Intensification and Kinetic Study

The present chapter highlights the kinetic studies for the sonochemical synthesis of peracetic acid (PAA) in a batch reactor. The effect of different operating parameters including acetic acid to hydrogen peroxide molar ratio, temperature, catalyst loading, effect of ultrasound, were studied using Amberlite IR-120H as a catalyst. The deactivation of the Amberlite IR-120H catalyst has also been studied. The experimental data were further utilized for the estimation of intrinsic reaction rate constants and equilibrium constants. From the experimental results; the optimized PAA concentration was observed for 471 mg/cm3 catalyst loading at 40°C with acetic acid to hydrogen peroxide molar ratio equals to 1:1 in the presence of ultrasound. Results also revealed that the reaction rate was found to be significantly enhanced in the presence of ultrasound, which can be attributed to the enhanced mixing and in-situ formation of H2O2. The use of ultrasound drastically reduces the overall reaction time to 60 min, which is very less compared to 30 h as reported for conventional batch reactor utilizing H2O2 only