Thesis (M.A. in National Security Affairs)--Naval Postgraduate School, June 2004. / Thesis advisor(s): Barak Salmoni. Includes bibliographical references. Also available online.

Thesis (M.S. in Aeronautical Engineering)--Naval Postgraduate School, September 1990. / Thesis Advisor(s): Netzer, D.W. Second Reader: Shreeve, R.P. "September 1990." Description based on title screen as viewed on December 17, 2009. DTIC Identifier(s): Nitrogen oxide, NOx control, gas turbine combustors, gas turbine fuel additives, soot control, pollution control. Author(s) subject terms: NOx control, gas turbine combustors, gas turbine fuel additives, soot control, pollution control. Includes bibliographical references (p. 65-66). Also available in print.

Large volumes of natural gas exist in tight fissured reservoirs. Hydraulic fracturing is one of the main stimulating techniques to enhance recovery from these fractured reservoirs. Although hydraulic fracturing has been used for decades for the stimulation of tight gas reservoirs, a thorough understanding of the interaction between induced hydraulic fractures and natural fractures is still lacking. Recent examples of hydraulic fracture diagnostic data suggest complex, multi-stranded hydraulic fracture geometry is a common occurrence. The interaction between pre-existing natural fractures and the advancing hydraulic fracture is a key condition leading to complex fracture patterns. Large populations of natural fractures that exist in formations such as the Barnett shale are sealed by precipitated cements which could be quartz, calcite, etc. Even though there is no porosity in the sealed fractures, they may still serve as weak paths for fracture initiation and/or for diverting the path of the growing hydraulic fractures. Performing hydraulic fracture design calculations under these complex conditions requires modeling of fracture intersections and tracking fluid fronts in the network of reactivated fissures. In this dissertation, the effect of the cohesiveness of the sealed natural fractures and the intact rock toughness in hydraulic fracturing are studied. Accordingly, the role of the pre-existing fracture geometry is also investigated. The results provide some explanations for significant differences in hydraulic fracturing in naturally fractured reservoirs from non-fractured reservoirs. For the purpose of this research, an extended finite element method (XFEM) code is developed to simulate fracture propagation, initiation and intersection. The motivation behind applying XFEM are the desire to avoid remeshing in each step of the fracture propagation, being able to consider arbitrary varying geometry of natural fractures and the insensitivity of fracture propagation to mesh geometry. New modifications are introduced into XFEM to improve stress intensity factor calculations, including fracture intersection criteria into the model and improving accuracy of the solution in near crack tip regions. The presented coupled fluid flow-fracture mechanics simulations extend available modeling efforts and provide a unified framework for evaluating fracture design parameters and their consequences. Results demonstrate that fracture pattern complexity is strongly controlled by the magnitude of in situ stress anisotropy, the rock toughness, the natural fracture cement strength, and the approach angle of the hydraulic fracture to the natural fracture. Previous studies (mostly based on frictional fault stability analysis) have concentrated on predicting the onset of natural fracture failure. However, the use of fracture mechanics and XFEM makes it possible to evaluate the progression of fracture growth over time as fluid is diverted into the natural fractures. Analysis shows that the growing hydraulic fracture may exert enough tensile and/or shear stresses on cemented natural fractures that they may be opened or slip in advance of hydraulic fracture tip arrival, while under some conditions, natural fractures will be unaffected by the hydraulic fracture. A threshold is defined for the fracture energy of cements where, for cases below this threshold, hydraulic fractures divert into the natural fractures. The value of this threshold is calculated for different fracture set orientations. Finally, detailed pressure profile and aperture distributions at the intersection between fracture segments show the potential for difficulty in proppant transport under complex fracture propagation conditions. Whether a hydraulic fracture crosses or is arrested by a pre-existing natural fracture is controlled by shear strength and potential slippage at the fracture intersections, as well as potential debonding of sealed cracks in the near-tip region of a propagating hydraulic fracture. We introduce a new more general criterion for fracture propagation at the intersections. We present a complex hydraulic fracture pattern propagation model based on the Extended Finite Element Method as a design tool that can be used to optimize treatment parameters under complex propagation conditions. / text

The objective of this paper is to help new investors and project developers identify the challenges of shale gas E&P and to enlighten them of the currently available strategies so that they can develop the best project plan and execute it without suffering unexpected challenges. This paper categorizes the challenges into five groups and concentrates on shale-gas-specific challenges. It excludes conventional oil and gas development challenges because by and large these five major challenge groups seem to decide the success and failure of most shale gas projects. The five groups are the identification of shale gas potentials, the technical challenges in well design and stimulation strategies, the economic challenges such as high cost of new technologies, the environmental challenges concerning the hydraulic fracturing water, and the international challenges of performing projects outside the US. The strategies are yet to be well established and are still evolving rapidly. Hence, before starting a shale gas project, shale gas developers need to perform extensive and intensive check-ups on the challenges and on current available strategies as well as to stay up to date thereafter on new strategies. / text

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During production from gas condensate reservoirs, significant productivity loss occurs after the pressure near the production wells drops below the dew point of the hydrocarbon fluid. Several methods such as gas recycling, hydraulic fracturing and solvent injection have been tried to restore gas production rates after a decline in well productivity owing to condensate and/or water blocking. These methods of well stimulation offer only temporary productivity restoration and cannot always be used for a variety of reasons. Significant advances have been made during this study to develop and extend a chemical treatment to reduce the damage caused by liquid (condensate + water) blocking in gas condensate reservoirs. The chemical treatment alters the wettability of water-wet sandstone rocks to neutral wet, and thus reduces the residual liquid saturations and increases gas relative permeability. The treatment also increases the mobility and recovery of condensate from the reservoir. A nonionic polymeric fluoro-surfactant in a glycol-alcohol solvent mixture improved the gas and condensate relative permeabilities by a factor of about 2 on various outcrop and reservoir sandstone rocks. The improvement in relative permeability after chemical treatment was quantified by performing high pressure and high temperature coreflood experiments on outcrop and reservoir cores using synthetic gas mixtures at reservoir conditions. The durability of the chemical treatment has been tested by flowing a large volume of gas-condensate fluids for a long period of time. Solvents used to dissolve and deliver the surfactant play an important part in the treatment, especially in the presence of high water saturation or high salinity brine. A screening test based on phase behavior studies of treatment solutions and brines has been used to select appropriate mixtures of solvents based on reservoir conditions. The adsorption of the surfactant on the rock surface has been measured by measuring the concentration of the surfactant in the effluent. Wettability of treated and untreated reservoir rocks has been analyzed by measuring the USBM and Amott-Harvey wettability indices to evaluate the effect of chemical treatment on wettability. For the first time, chemical treatments have also been shown to remove the damage caused by water blocking in gas wells and for increasing the fracture conductivity and thus productivity of fractured gas-condensate wells. Core flood experiments done on propped fractures show significant improvement in gas and condensate relative permeability due to surface modification of proppants by chemical reatment. Relative permeability measurements have been done on sandstone and limestone cores over a wide range of conditions including high velocities typical of high rate gas wells and corresponding to both high capillary numbers and non-Darcy flow. A new approach has been presented to express relative permeability as a function three non-dimensionless terms; capillary number, modified Reynolds Number and PVT ratio. Numerical simulations using a compositional simulator have been done to better understand and design well treatments as a function of treatment volume and other parameters. Injection of treatment solution and chase gas and the flow back of solvents were simulated. These simulations show that chemical treatments have the potential to greatly increase production with relatively small treatment volumes since only the near-well region blocked by condensate and/or water needs to be treated.

The shift of hydrocarbon exploration and production to deepwater has resulted in new opportunities for the petroleum industry(in this project, the deepwater depth greater than 1,000 ft) but also, it has introduced new challenges. In 2001,more than 999 Bcf of associated gas were produced from the Gulf of Mexico, with deepwater associated gas production accounting for 20% of this produced gas. Two important issues are the potential environmental impacts and the economic value of deepwater associated gas. This project was designed to test the viability of storing associated gas in a saline sandstone aquifer above the producing horizon. Saline aquifer storage would have the dual benefits of gas emissions reduction and gas storage for future use. To assess the viability of saline aquifer storage, a simulation study was conducted with a hypothetical sandstone aquifer in an anticlinal trap. Five years of injection were simulated followed by five years of production (stored gas recovery). Particular attention was given to the role of relative permeability hysteresis in determining trapped gas saturation, as it tends to control the efficiency of the storage process. Various cases were run to observe the effect of location of the injection/production well and formation dip angle. This study was made to: (1) conduct a simulation study to investigate the effects of reservoir and well parameters on gas storage performance; (2) assess the drainage and imbibition processes in aquifer gas storage; (3) evaluate methods used to determine relative permeability and gas residual saturation ; and (4) gain experience with, and confidence in, the hysteresis option in IMEX Simulator for determining the trapped gas saturation. The simulation results show that well location and dip angle have important effects on gas storage performance. In the test cases, the case with a higher dip angle favors gas trapping, and the best recovery is the top of the anticlinal structure. More than half of the stored gas is lost due to trapped gas saturations and high water saturation with corresponding low gas relative permeability. During the production (recovery) phase, it can be expected that water-gas production ratios will be high. The economic limit of the stored gas recovery will be greatly affected by producing water-gas ratio, especially for deep aquifers. The result indicates that it is technically feasible to recover gas injected into a saline aquifer, provided the aquifer exhibits the appropriate dip angle, size and permeability, and residual or trapped gas saturation is also important. The technical approach used in this study may be used to assess saline aquifer storage in other deepwater regions, and it may provide a preliminary framework for studies of the economic viability of deepwater saline aquifer gas storage.

This thesis examines the prospect of structure H (sH) hydrate to be exploited for methane storage. The methane content in the hydrate, hydrate kinetics and conversion rates are areas of particular importance. Experiments and theory are employed at the macroscopic and molecular levels to study the relevant phenomena. sH hydrate was successfully synthesized from ice particles with full conversion achieved within a day when thermal ramping above the ice melting point was applied. It was found that a polar guest (tert-butyl methyl ether / TBME) wets ice more extensively compared to two hydrophobic guests (neo-hexane / NH and methyl-cyclohexane / MCH). TBME also has much higher solubility in water. Consequently, the system with TBME was found to exhibit the highest initial hydrate formation rate from ice particles or in water in a well stirred vessel. However, the rate with the hydrophobic guests was the fastest when the temperature exceeded the ice point. Thus, the applied temperature ramping compensated the slow kinetics below the ice point for the hydrophobic guests and allowed faster overall conversion than the polar guest. Structure, cage occupancy, composition and methane content in the hydrate were also determined by employing different techniques and the results were found to be consistent. It was found that the methane content in structure H hydrate with TBME was the smallest (103-125 v/v) whereas that with NH was 130-139 (v/v) and that with MCH was 132-142 (v/v). The methane content in structure II hydrate by using propane (C₃H₈) and tetrahydrofuran (THF) as the large guest molecule were also estimated. Optimal methane content was found at approximately 100 (v/v) for both C₃H₈ and THF systems with the large guest concentrations at 1% for C₃H₈ (10°C) and 1% for THF (room temperature). The gas content is of course lower than that for structure I hydrate (170 v/v) but one should consider the fact that the hydrate formation conditions are much lower (less than 1 MPa). Finally, MD simulations revealed for the first time the formation of defects in the cavities for the TBME/methane/water (sH hydrate) system which may affect hydrate stability and kinetics.

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