Relevant bibliographies by topics / Natural gas Gas reservoirs. Thermodynamics

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Academic literature on the topic 'Natural gas Gas reservoirs. Thermodynamics'

Author: Grafiati
Published: 4 June 2021
Last updated: 6 February 2022

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Journal articles on the topic "Natural gas Gas reservoirs. Thermodynamics"

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Farzaneh-Gord, Mahmood, and Mahdi Deymi-Dashtebayaz. "Optimizing Natural Gas Fueling Station Reservoirs Pressure Based on Ideal Gas Model." Polish Journal of Chemical Technology 15, no. 1 (March 1, 2013): 88–96. http://dx.doi.org/10.2478/pjct-2013-0015.

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At CNG fuelling station, natural gas is usually stored in a cascade storage system to utilize the station more efficient. The cascade storage system is generally divided into three reservoirs, commonly termed low, medium and high-pressure reservoirs. The pressures within these three reservoirs have huge effects on the performance of a CNG fuelling station and a fast filling process of natural gas vehicle’s (NGV) cylinder. A theoretical analysis is developed to study the effects of the reservoirs pressures and temperatures on the performance of the CNG station. The analysis is based on the first and the second law of thermodynamics, conservation of mass and ideal gas assumptions. The results show that as the reservoir temperature decreases, the fill ratio increases and the pressure within the filling station reservoirs has no effects on the fill ratio. The non-dimensional entropy generation and filling time profiles have opposite trends and as entropy generation decreases, the filling time increases. The optimized non-dimensional low and medium pressure-reservoir pressures are found to be as 0.24 and 0.58 respectively in thermodynamic point of view.
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O'Sullivan, M. J., G. S. Bodvarsson, K. Pruess, and M. R. Blakeley. "Fluid and Heat Flow In Gas-Rich Geothermal Reservoirs." Society of Petroleum Engineers Journal 25, no. 02 (April 1, 1985): 215–26. http://dx.doi.org/10.2118/12102-pa.

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Abstract Numerical simulation techniques are used to study the effects of noncondensable gases (CO2) on geothermal reservoir behavior in the natural state and during exploitation. It is shown that the presence Of CO2 has a large effect on the thermodynamic conditions of a reservoir in the natural state, especially on temperature distributions and phase compositions. The gas will expand two-phase zones phase compositions. The gas will expand two-phase zones and increase gas saturations to enable flow of CO2 through the system. During exploitation, the early pressure drop primarily results from "degassing" of the system. This primarily results from "degassing" of the system. This process can cause a very rapid initial pressure drop, on process can cause a very rapid initial pressure drop, on the order of megapascals, depending on the initial partial pressure of CO2. The flowing gas content from wells can pressure of CO2. The flowing gas content from wells can provide information on in-place gas saturations and provide information on in-place gas saturations and relative permeability curves that apply at a given geothermal resource. Site-specific studies are made for the gas-rich, two-phase reservoir at the Ohaaki geothermal field in New Zealand. A simple lumped-parameter model and a vertical column model are applied to the field data. The results obtained agree well with the natural thermodynamic state of the Ohaaki field (pressure and temperature profiles) and a partial pressure of 1.5 to 2.5 MPa [217 to 363 psi] is calculated in the primary reservoirs. The models also agree reasonably well with field data obtained during exploitation of the field. The treatment of thermophysical properties of H2O/CO2 mixtures for different phase compositions is summarized. Introduction Many geothermal reservoirs contain large amounts of non-condensable gases, particularly CO2. The proportion of noncondensable gas in the produced fluid is an extremely important factor in the design of separators, turbines, heat exchangers, and other surface equipment. In the reservoir itself, the presence of CO2 significantly alters the distribution of temperature and gas saturation (volumetric fraction of gas phase) associated with given heat and mass flows. Therefore, when modeling gas-rich reservoirs it is essential to keep track of the amount of CO2 in each gridblock in addition to the customary fluid and heat content. Several investigators have considered the effects of CO2 on the reservoir dynamics of geothermal systems. A lumped-parameter model using one block for the gas zone and one for the liquid zone was developed by Atkinson et al. for the Bagnore (Italy) reservoir. Preliminary work on the Ohaaki reservoir was carried out by Zyvoloski and O'Sullivan, but these studies were limited because-the thermodynamic package used could only handle two-phase conditions. Generic studies of reservoir depletion and well-test analysis also were made in the previous works. The present study describes the effects of CO2 in geothermal reservoirs in a more complete and detailed way. We emphasize the potential for using the CO2 content in the fluid produced during a well test as a reservoir diagnostic aid, and as a means of gaining information about relative permeability curves. The aim of the present study is to investigate the effects of CO2 on both the natural state of a reservoir and its behavior under exploitation. Several generic simulation studies are described. First, the effect of CO2 on the depletion of a single-block, lumped-parameter reservoir model is briefly examined. Secondly, the relationship between the mass fraction Of CO2 in the produced fluid and the mass fraction in place in the reservoir is studied. It is demonstrated that in some cases the in-place gas saturation can be determined for a given set of relative permeability curves. Finally, the effects of CO2 on the permeability curves. Finally, the effects of CO2 on the vertical distribution of gas saturation, temperature, and pressure of geothermal reservoirs in the natural state are pressure of geothermal reservoirs in the natural state are investigated. The numerical simulator with the H2O/CO2 thermodynamic package is applied to field data from the Ohaaki (formerly Broadlands) geothermal field in New Zealand. Two simple models of the 1966–74 large-scale field exploitation test of the Ohaaki reservoir are presented. The first is a single-block, lumped-parameter model similar to those reported earlier by Zyvoloski and O'Sullivan and Grant. In the former work, a less accurate thermodynamic package for H2O/CO2 mixtures is used; the latter uses approximate methods to integrate the mass-, energy-, and CO2-balance equations. The second model described in the present work is a distributed-parameter model, in the form of a vertical column representing the main upflow zone at Ohaaki. This model produces a good fit to the observed distribution of pressure and temperature with depth in the natural state at Ohaaki and a good match to the observed response of the reservoir during 5 years of experimental production and 3 years of recovery. SPEJ p. 215
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Lupu, Diana-Andreea, and Dan-Paul Stefanescu. "Natural gas hydrates vs. induced dysfunctions in the hydrocarbon extraction process." MATEC Web of Conferences 343 (2021): 09004. http://dx.doi.org/10.1051/matecconf/202134309004.

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Cantoned fluids in porous-permeable or fractured media of reservoirs have acquired during the geological time special properties. The fluids from the reservoir could be or not a mixture of reservoir water, liquid hydrocarbons and gaseous hydrocarbons. Considering if inside of a reservoir there are two types of substances like natural gas and reservoir water which may be in the form of vaporous than the condition of saturation of gases with water vaporous is fulfilled. This process is taking place due to thermodynamic equilibrium resulting the so-called gas humidity. This state corroborated with a certain chemical composition plus favourable values of pressure and temperature may be decisive in the appearance of hydrates. In this scientific paper they will be presented from a theoretical and practical point of view the favourable conditions of gas hydrates appearance and the specific ways of inhibiting the formation of this compounds. A case study in which through modelling and numerical simulation of the behaviour of a productive natural gas well will provide a series of data related to this phenomenon. The specific modelling and numerical simulation was adapted to the conditions of formation and subsequently the elimination of the appearance of hydrates.
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Swinkels, Wim J. A. M., and Rik J. J. Drenth. "Thermal Reservoir Simulation Model of Production From Naturally Occurring Gas Hydrate Accumulations." SPE Reservoir Evaluation & Engineering 3, no. 06 (December 1, 2000): 559–66. http://dx.doi.org/10.2118/68213-pa.

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Summary Reservoir behavior of a hydrate-capped gas reservoir is modeled using a three-dimensional thermal reservoir simulator. The model incorporates a description of the phase behavior of the hydrates, heat flow and compaction in the reservoir and the hydrate cap. The model allows the calculation of well productivity, evaluation of well configurations and matching of experimental data. It shows the potentially self-sealing nature of the hydrate cap. Production scenarios were also investigated for production from the solid hydrate cap using horizontal wells and various ways of dissociating the gas hydrates. These investigations show the role of excessive water production and the requirement for water handling facilities. A data acquisition program is needed to obtain reservoir parameters for gas hydrate accumulations. Such parameters include relative phase permeability, heat capacity and thermal conductivity of the hydrate-filled formations, compaction parameters and rate of hydrate formation and decomposition in the reservoir. Introduction Interest in natural gas hydrates is increasing with foreseen requirements in the next century for large volumes of natural gas as a relatively clean hydrocarbon fuel and with increasing exploration and production operation experience in deepwater and Arctic drilling. While progress is being made in identifying and drilling natural gas hydrates, there is also the need to look ahead and develop production concepts for the potentially large deposits of natural gas hydrates and hydrate-capped gas reservoirs. We are now reaching the stage in which some of the simplifying assumptions of analytical models are not sufficient any longer for developing production concepts for natural gas hydrate accumulations. For this reason we have investigated the option of applying a conventional industrial thermal reservoir simulator to model production from natural gas hydrates. Reservoir behavior of free gas trapped under a hydrate seal is to a great extent similar to the behavior of a conventional gas field with the following major differences:thermal effects on the overlying hydrate cap have to be taken into account;potentially large water saturations can build up in the reservoir;relatively low pressures;high formation compressibility can be expected. Use of a thermal compositional reservoir simulator to model the behavior of hydrates and hydrate-capped gas has not been attempted before. We have shown before1 that existing knowledge of phase behavior and thermal reservoir modeling can be fruitfully combined to better understand the behavior of natural gas hydrates in the subsurface. In this paper we will expand on this work and provide further results. After an overview of the model setup, we will first show some results for modeling the depletion of the gas accumulations underlying the hydrate layer. This will be followed by the results for production from the hydrate layer itself, applying heat injection in the formation. Modeling Natural Hydrate Associated Production Attempts to model the behavior of hydrate-capped gas and hydrate reservoirs have been documented by various authors in the literature. Simple energy balance approaches are used by Kuuskraa and Hammershaimb et al.2 Masuda et al.,3 Yousif et al.,4 and Xu and Ruppel5 have presented numerical solutions to analytical models. The first two of these papers do not include thermal effects in their calculations. Reference 5 is specifically aimed at the formation phase of hydrates in the reservoir over geological times, and is less relevant to the production phase. An attempt at explaining the production behavior of a possibly hydrate-capped gas accumulation is described by Collett and Ginsburg.6 The depth and thickness of the hydrate layer under various conditions were described by Holder et al.7 and by Hyndman et al.8 All these approaches apply analytical methods to explain the subsurface occurrence and behavior of natural gas hydrates using various simplifying assumptions. In earlier work1 we have shown that modeling the reservoir behavior of hydrate-capped gas reservoirs with a three-dimensional (3D) thermal hydrocarbon reservoir simulator allows us to account for reservoir aspects, which are disregarded in most analytical models. Such aspects includewell inflow pressure drop and the effects of horizontal and vertical wells in the reservoir;heat transfer between the reservoir fluids and the formation;the geothermal gradient;phase behavior and pressure/volume/temperature (PVT) properties of the reservoir fluids as a fluction of pressure decline;internal architecture and geometry of the reservoir; andreservoir compaction effects. Objective The current study was undertaken to show the feasibility of modeling production behavior of a hydrate-capped gas reservoir in a conventional 3D thermal reservoir simulation model. Objectives of the modeling work include the following.Understand reservoir behavior of natural gas hydrates and hydrate-capped reservoirs. Important aspects of the reservoir thermodynamics are the potential self-preservation capacity of the hydrate cap, the limitation on hydrate decomposition imposed by the thermal conductivity of the rock and the influence of compaction.Confirm material and energy balance analytical calculations.Investigate production options, such as the application of horizontal wells.Calculate well productivity and evaluate well configurations. This study was performed as part of an ongoing project involving other geological and petroleum engineering disciplines. Accounting for Thermal Effects In this study the thermal version of an in-house hydrocarbon reservoir simulator is used.9 We represent the reservoir fluids by a gaseous, a hydrate and an aqueous phase, which are made up of three components, two hydrocarbons and a water component.
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Kuczyński, Szymon. "Analysis of Vapour Liquid Equilibria in Unconventional Rich Liquid Gas Condensate Reservoirs." ACTA Universitatis Cibiniensis 65, no. 1 (December 1, 2014): 46–51. http://dx.doi.org/10.1515/aucts-2015-0008.

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Abstract At the beginning of 21st century, natural gas from conventional and unconventional reservoirs has become important fossil energy resource and its role as energy fuel has increased. The exploration of unconventional gas reservoirs has been discussed recently in many conferences and journals. The paper presents considerations which will be used to build the thermodynamic model that will describe the phenomenon of vapour - liquid equilibrium (VLE) in the retrograde condensation in rocks of ultra-low permeability and in the nanopores. The research will be limited to "tight gas" reservoirs (TGR) and "shale gas" reservoirs (SGR). Constructed models will take into account the phenomenon of capillary condensation and adsorption. These studies will be the base for modifications of existing compositional simulators
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Al-Abri, Abdullah, and Robert Amin. "Numerical simulation of CO2 injection into fractured gas condensate reservoirs." APPEA Journal 51, no. 2 (2011): 742. http://dx.doi.org/10.1071/aj10122.

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More than sixty percent of the world’s remaining oil reserves are hosted by intensely fractured porous rocks, such as the carbonate sequences of Iran, Iraq, Oman, or offshore Mexico (Bedoun, 2002). The high contrast of capillarity between the matrix and the fractures makes a significant difference in the recovery performance of fractured and non-fractured reservoirs (Lemonnier and Bourbiaux, 2010). Simulation of naturally fractured reservoirs is a challenging task from both a reservoir description and a numerical standpoint (Selley, 1998). This paper presents the recovery performance of CO2 injection into a local fractured and faulted gas condensate reservoir in Western Australia. Tempest 6.6 compositional simulation model was used to evaluate the performance of uncertain reservoir parameters, injection design variables, and economic recovery factors associated with CO2 injection. The model incorporates experimental IFT, relative permeability data and solubility data at various thermodynamic conditions for the same field. These measurements preceded the simulation work and are now published in various places. The model uses Todd-Longstaff mixing algorithm to control the displacement front expansion. This paper will present, with aid of simulation output graph and tornado charts, the results of natural depletion, miscible and immiscible CO2 injection, waterflooding, WAG, sensitivity of fracture porosity, permeability and fracture intensity. The results also demonstrate the effect of initial reservoir composition, well completion and injection flow rate. All simulation cases were carried out at various injection pressures. The results are discussed in terms of transport mechanisms and fluid dynamics. This project was sponsored by a consortium of companies.
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Sergeeva, Daria, Vladimir Istomin, Evgeny Chuvilin, Boris Bukhanov, and Natalia Sokolova. "Influence of Hydrate-Forming Gas Pressure on Equilibrium Pore Water Content in Soils." Energies 14, no. 7 (March 26, 2021): 1841. http://dx.doi.org/10.3390/en14071841.

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Natural gas hydrates (primarily methane hydrates) are considered to be an important and promising unconventional source of hydrocarbons. Most natural gas hydrate accumulations exist in pore space and are associated with reservoir rocks. Therefore, gas hydrate studies in porous media are of particular interest, as well as, the phase equilibria of pore hydrates, including the determination of equilibrium pore water content (nonclathrated water). Nonclathrated water is analogous to unfrozen water in permafrost soils and has a significant effect on the properties of hydrate-bearing reservoirs. Nonclathrated water content in hydrate-saturated porous media will depend on many factors: pressure, temperature, gas composition, the mineralization of pore water, etc. In this paper, the study is mostly focused on the effect of hydrate-forming gas pressure on nonclathrated water content in hydrate-bearing soils. To solve this problem, simple thermodynamic equations were proposed which require data on pore water activity (or unfrozen water content). Additionally, it is possible to recalculate the nonclathrated water content data from one hydrate-forming gas to another using the proposed thermodynamic equations. The comparison showed a sufficiently good agreement between the calculated nonclathrated water content and its direct measurements for investigated soils. The discrepancy was ~0.15 wt% and was comparable to the accuracy of direct measurements. It was established that the effect of gas pressure on nonclathrated water content is highly nonlinear. For example, the most pronounced effect of gas pressure on nonclathrated water content is observed in the range from equilibrium pressure to 6.0 MPa. The developed thermodynamic technique can be used for different hydrate-forming gases such as methane, ethane, propane, nitrogen, carbon dioxide, various gas mixtures, and natural gases.
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Deymi-Dashtebayaz, Mahdi, Mahmood Farzaneh-Gord, and Hamid Reza Rahbari. "Simultaneous thermodynamic simulation of CNG filling process." Polish Journal of Chemical Technology 16, no. 1 (March 1, 2014): 7–14. http://dx.doi.org/10.2478/pjct-2014-0002.

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Abstract In CNG station, the fuel is usually stored in the cascade storage bank to utilize the station more efficiently. The cascade storage bank is generally divided into three reservoirs, commonly termed low, medium and high-pressure storage bank. The pressures within these reservoirs have huge effects on the performance of the stations. In the current study, a theoretical simulation based on mass balance and thermodynamic laws has been developed to study the dynamic fast fi lling process of vehicle’s (NGV) cylinder from the cascade storage bank. The dynamic change of the parameters within the storage bank is also considered. Natural gas is assumed to contain only its major component, methane, and so thermodynamic properties table has been employed for finding the thermodynamics properties. Also the system is assumed as a lumped adiabatic system. The results show that the initial pressure of the cascade storage bank has a big effect on the storage bank volumes for bringing up the NGV cylinder to its target pressure (200 bar). The results also showed that ambient temperature has effect on the refueling process, chiefly the final NGV cylinder and the cascade storage bank conditions
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Nago, Annick, and Antonio Nieto. "Natural Gas Production from Methane Hydrate Deposits Using Clathrate Sequestration: State-of-the-Art Review and New Technical Approaches." Journal of Geological Research 2011 (August 28, 2011): 1–6. http://dx.doi.org/10.1155/2011/239397.

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This paper focuses on reviewing the currently available solutions for natural gas production from methane hydrate deposits using CO2 sequestration. Methane hydrates are ice-like materials, which form at low temperature and high pressure and are located in permafrost areas and oceanic environments. They represent a huge hydrocarbon resource, which could supply the entire world for centuries. Fossil-fuel-based energy is still a major source of carbon dioxide emissions which contribute greatly to the issue of global warming and climate change. Geological sequestration of carbon dioxide appears as the safest and most stable way to reduce such emissions for it involves the trapping of CO2 into hydrocarbon reservoirs and aquifers. Indeed, CO2 can also be sequestered as hydrates while helping dissociate the in situ methane hydrates. The studies presented here investigate the molecular exchange between CO2 and CH4 that occurs when methane hydrates are exposed to CO2, thus generating the release of natural gas and the trapping of carbon dioxide as gas clathrate. These projects include laboratory studies on the synthesis, thermodynamics, phase equilibrium, kinetics, cage occupancy, and the methane recovery potential of the mixed CO2–CH4 hydrate. An experimental and numerical evaluation of the effect of porous media on the gas exchange is described. Finally, a few field studies on the potential of this new gas hydrate recovery technique are presented.
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Zuo, Lin, Lixia Sun, and Changfu You. "Latest progress in numerical simulations on multiphase flow and thermodynamics in production of natural gas from gas hydrate reservoir." Frontiers of Energy and Power Engineering in China 3, no. 2 (March 5, 2009): 152–59. http://dx.doi.org/10.1007/s11708-009-0017-x.

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Dissertations / Theses on the topic "Natural gas Gas reservoirs. Thermodynamics"

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Garapati, Nagasree. "Determination of mixed hydrate thermodynamics for reservoir modeling." Morgantown, W. Va. : [West Virginia University Libraries], 2009. http://hdl.handle.net/10450/10623.

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Thesis (M.S.)--West Virginia University, 2009.
Title from document title page. Document formatted into pages; contains ix, 97 p. : ill. (some col.), col. map. Includes abstract. Includes bibliographical references.
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Alp, Doruk. "Gas Production From Hydrate Reservoirs." Master's thesis, METU, 2005. http://etd.lib.metu.edu.tr/upload/12606241/index.pdf.

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In this study
gas production by depressurization method from a hydrate reservoir containing free gas zone below the hydrate zone is numerically modeled through 3 dimensional, 3 phase, non-isothermal reservoir simulation. The endothermic nature of hydrate decomposition requires modeling to be non-isothermal
hence energy balance equations must be employed in the simulation process. TOUGH-Fx, the successor of the well known multipurpose reservoir simulator TOUGH2 (Pruess [24]) and its very first module TOUGH-Fx/Hydrate, both developed by Moridis et.al [23] at LBNL, are utilized to model production from a theoretical hydrate reservoir, which is first studied by Holder [11] and then by Moridis [22], for comparison purposes. The study involves 2 different reservoir models, one with 30% gas in the hydrate zone (case 1) and other one with 30% water in the hydrate zone (case 2). These models are further investigated for the effect of well-bore heating. The prominent results of the modeling study are: &
#8226
In case 1, second dissociation front develops at the top of hydrate zone and most substantial methane release from the hydrate occurs there. &
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In case 2 (hydrate-water in the hydrate zone), because a second dissociation front at the top of hydrate zone could not fully develop due to high capillary pressure acting on liquid phase, a structure similar to ice lens formation is observed. &
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Initial cumulative replenishment (first 5 years) and the replenishment rate (first 3.5 years) are higher for case 2 because, production pressure drop is felt all over the reservoir due to low compressibility of water and more hydrate is decomposed. Compared to previous works of Holder [11] and Moridis [22], amount of released gas contribution within the first 3 years of production is significantly low which is primarily attributed to the specified high capillary pressure function.
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Sun, Duo. "Storage of carbon dioxide in depleted natural gas reservoirs as gas hydrate." Thesis, University of British Columbia, 2016. http://hdl.handle.net/2429/59341.

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More than 120 depleted natural gas reservoirs in Alberta, Canada have been identified as potential sites for CO₂ storage at temperature and pressure conditions at which CO₂ may form gas hydrate. Reservoir simulations presented in the literature have demonstrated the feasibility of storing CO₂ in such reservoirs. In this thesis, the injection of CO₂ in a laboratory size reservoir (packed bed of silica particles) serving as a physical model for a depleted reservoir was studied. The hypothesis was that injecting CO₂ into the reservoir at gas hydrate formation conditions will be beneficial in terms of increased CO₂ storage density. It is noted that CO₂ is stored not only as hydrate but also some is dissolved in the residual pore water (not converted to hydrate) and some as a gas in the remaining pore space. The results indicate that hydrate formation enhances the CO₂ storage density. The work also demonstrated that substances like tapioca starch added to the water in small quantities (1 wt %) delayed the onset of hydrate nucleation in the earlier stage but subsequently more CO₂ was stored as hydrate compared to the tapioca starch-free systems. The delay in nucleation decreases the risk to form a hydrate plug in the injection system. The injection of the CO₂-rich mixture (90 mol % CO₂/10 mol % N₂), which is a typical composition of a flue gas after CO₂ capture process, into a reservoir with CH4 (simulating residual natural gas) was also studied in the laboratory reservoir. It was found that the total CO₂ storage density (in hydrate, gaseous and dissolved state) decreased from 143 kg/m³ (the CO₂ injection into a CH₄ free reservoir) to 119 kg/m³. Finally, relevant phase equilibrium data were obtained in a constant volume high pressure vessel and by calorimetry. The results were found to be in good agreement with thermodynamic model calculated values within ± 40 kPa and ± 0.2 K, respectively.
Applied Science, Faculty of
Chemical and Biological Engineering, Department of
Graduate
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Solbraa, Even. "Equilibrium and Non-Equilibrium Thermodynamics of Natural Gas Processing." Doctoral thesis, Norwegian University of Science and Technology, Faculty of Engineering Science and Technology, 2002. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-96.

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The objective of this work has been to study equilibrium and non equilibrium situations during high pressure gas processing operations with emphasis on utilization of the high reservoir pressure. The well stream pressures of some of the condensate and gas fields in the North Sea are well above 200 bar. Currently the gas is expanded to a specified processing condition, typically 40-70 bar, before it is recompressed to the transportation conditions. It would be a considerable environmental and economic advantage to be able to process the natural gas at the well stream pressure. Knowledge of thermodynamic- and kinetic properties of natural gas systems at high pressures is needed to be able to design new high pressure process equipment.

Nowadays, reactive absorption into a methyldiethanolamine (MDEA)solution in a packed bed is a frequently used method to perform acid gas treating. The carbon dioxide removal process on the Sleipner field in the North Sea uses an aqueous MDEA solution and the operation pressure is about 100 bar. The planed carbon dioxide removal process for the Snøhvit field in the Barents Sea is the use of an activated MDEA solution.

The aim of this work has been to study high-pressure effects related to the removal of carbon dioxide from natural gas. Both modelling and experimental work on high-pressure non-equilibrium situations in gas processing operations have been done.

Few experimental measurements of mass transfer in high pressure fluid systems have been published. In this work a wetted wall column that can operate at pressures up to 200 bar was designed and constructed. The wetted wall column is a pipe made of stainless steel where the liquid is distributed as a thin liquid film on the inner pipewall while the gas flows co- or concurrent in the centre of the pipe. The experiments can be carried out with a well-defined interphase area and with relatively simple fluid mechanics. In this way we are able to isolate the effects we want to study in a simple and effective way.

Experiments where carbon dioxide was absorbed into water and MDEA solutions were performed at pressures up to 150 bar and at temperatures 25 and 40°C. Nitrogen was used as an inert gas in all experiments.

A general non-equilibrium simulation program (NeqSim) has been developed. The simulation program was implemented in the object-oriented programming language Java. Effort was taken to find an optimal object-oriented design. Despite the increasing popularity of object-oriented programming languages such as Java and C++, few publications have discussed how to implement thermodynamic and fluid mechanic models. A design for implementation of thermodynamic, mass transfer and fluid mechanic calculations in an object-oriented framework is presented in this work.

NeqSim is based on rigorous thermodynamic and fluid mechanic models. Parameter fitting routines are implemented in the simulation tool and thermodynamic-, mass transfer- and fluid mechanic models were fitted to public available experimental data. Two electrolyte equations of state were developed and implemented in the computer code. The electrolyte equations of state were used to model the thermodynamic properties of the fluid systems considered in this work (non-electrolyte, electrolyte and weak-electrolyte systems).

The first electrolyte equation of state (electrolyte ScRK-EOS) was based on a model previously developed by Furst and Renon (1993). The molecular part of the equation was based on a cubic equation of state (Scwarzentruber et.al. (1989)’s modification of the Redlich-Kwong EOS) with the Huron-Vidal mixing rule. Three ionic terms were added to this equation – a short-range ionic term, a long-range ionic term (MSA) and a Born term. The thermodynamic model has the advantage that it reduces to a standard cubic equation of state if no ions are present in the solution, and that public available interaction parameters used in the Huron-Vidal mixing rule could be utilized. The originality of this electrolyte equation of state is the use of the Huron-Vidal mixing rule and the addition of a Born term. Compared to electrolyte models based on equations for the gibbs excess energy, the electrolyte equation of state has the advantage that the extrapolation to higher pressures and solubility calculations of supercritical components is less cumbersome. The electrolyte equation of state was able to correlate and predict equilibrium properties of CO2-MDEA-water solutions with a good precision. It was also able to correlate high pressure data of systems of methane-CO2-MDEA and water.

The second thermodynamic model (electrolyte CPA-EOS) evaluated in this work is a model where the molecular interactions are modelled with the CPA (cubic plus association) equation of state (Kontogeorgios et.al., 1999) with a classical one-parameter Van der Walls mixing rule. This model has the advantage that few binary interaction parameters have to be used (even for non-ideal solutions), and that its extrapolation capability to higher pressures is expected to be good. In the CPA model the same ionic terms are used as in the electrolyte ScRK-EOS.

A general non-equilibrium two-fluid model was implemented in the simulation program developed in this work. The heat- and mass-transfer calculations were done using an advanced multicomponent mass transfer model based on non-equilibrium thermodynamics. The mass transfer model is flexible and able to simulate many types of non-equilibrium processes we find in the petroleum industry. A model for reactive mass transfer using enhancement factors was implemented for the calculation of mass transfer of CO2 into amine solutions. The mass transfer model was fitted to the available mass transfer data found in the open literature.

The simulation program was used to analyse and perform parameter fitting to the high pressure experimental data obtained during this work. The mathematical models used in NeqSim were capable of representing the experimental data of this work with a good precision. From the experimental and modelling work done, we could conclude that the mass transfer model regressed to pure low-pressure data also was able to represent the high-pressure mass transfer data with an acceptable precision. Thus the extrapolation capability of the model to high pressures was good.

For a given partial pressure of CO2 in the natural gas, calculations show a decreased CO2 capturing capacity of aqueous MDEA solutions at increased natural gas system pressure. A reduction up to 40% (at 200 bar) compared to low pressure capacity is estimated. The pressure effects can be modelled correctly by using suitable thermodynamic models for the liquid and gas. In a practical situation, the partial pressure of CO2 in the natural gas will be proportional to the total pressure. In these situations, it is shown that the CO2 capturing capacity of the MDEA solution will be increased at rising total pressures up to 200 bar. However, the increased capacity is not as large as we would expect from the higher CO2 partial pressure in the gas.

The reaction kinetics of CO2 with MDEA is shown to be relatively unaffected by the total pressure when nitrogen is used as inert gas. It is however important that the effects of thermodynamic and kinetic non- ideality in the gas and liquid phase are modelled in a consistent way. Using the simulation program NeqSim – some selected high-pressure non-equilibrium processes (e.g. absorption, pipe flow) have been studied. It is demonstrated that the model is capable of simulating equilibrium- and non-equilibrium processes important to the process- and petroleum industry.

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Smith, Vicky S. "Solid-fluid equilibria in natural gas systems." Diss., Georgia Institute of Technology, 1995. http://hdl.handle.net/1853/10095.

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Tost, Brian Christopher. "Low porosity mistaken for natural gas hydrate at Alaminos Canyon, Gulf of Mexico: Implications for gas hydrate exploration in marine sediment reservoirs." The Ohio State University, 2013. http://rave.ohiolink.edu/etdc/view?acc_num=osu1366475207.

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Srinivasan, Balaji S. "The impact of reservoir properties on mixing of inert cushion and natural gas in storage reservoirs." Morgantown, W. Va. : [West Virginia University Libraries], 2006. https://eidr.wvu.edu/etd/documentdata.eTD?documentid=4653.

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Thesis (M.S.)--West Virginia University, 2006.
Title from document title page. Document formatted into pages; contains vii, 88 p. : ill. (some col.), map (part col.). Includes abstract. Includes bibliographical references (p. 47-49).
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Loomis, Ian Morton. "Experiments Concerning the Commercial Extraction of Methane from Coalbed Reservoirs." Diss., Virginia Tech, 1997. http://hdl.handle.net/10919/30485.

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In late 1992 coalbed methane became the most significant source of natural gas produced in Virginia. This gas is held within the coal formations adsorbed to the coal matrix. The current well stimulation technology applies a high pressure fluid to the coal formation surrounding the wellbore to induce a series of fractures. The research documented in this thesis investigates several new technologies that could replace or augment the current well stimulation approach of hydraulic fracturing. The application of liquid carbon dioxide, as the stimulation agent was investigated in a series of permeability tests. These measurements were made using a radial flow technique developed specifically for this research project. The results of the tests using liquid carbon dioxide to enhance the permeability of coal samples, to methane gas, indicated a significant increase in permeability of the samples. Comparison to a reference material showed, however, that the increase was of a general nature, not by specific interaction with the coal matrix. Rather, the permeability increase was due to reduced resistance of the borehole skin. Studies of the new, radial flow, permeability measurement approach showed good agreement to a conventional, axial flow, approach for similar sample bedding orientation to the gas flow. The documented experiments also include investigations into the potential for using custom designed nitrocellulose/nitroglycerin/RDX based propellant charges to produce extensive fracturing away from the wellbore. The first series of these experiments concerned the characterization of the burn properties for these propellants and their mixtures. Utilizing an interior ballistics approach, these laboratory small-scale shots were numerically modeled with a program written as a part of this project. Using the small-scale results and the modeled data, a series of large-scale test shots were developed and fired to gain understanding of the scale effects. The small-scale constant volume bomb, and the large-scale vented bomb were both custom designed and fabricated for this project. Comparisons of the laboratory data and modeled predictions show good agreement for both the small and large-scale test series. This work concludes by presenting considerations for utilizing the propellant based well stimulation approach in the water filled wells in southwest Virginia.
Ph. D.
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Choi, Jong-Won. "Geomechanics of subsurface sand production and gas storage." Diss., Georgia Institute of Technology, 2011. http://hdl.handle.net/1853/39493.

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Improving methods of hydrocarbon production and developing new techniques for the creation of natural gas storage facilities are critically important for the petroleum industry. This dissertation focuses on two key topics: (1) mechanisms of sand production from petroleum reservoirs and (2) mechanical characterization of caverns created in carbonate rock formations for natural gas storage. Sand production is the migration of solid particles together with the hydrocarbons when extracted from petroleum reservoirs. It usually occurs from wells in sandstone formations that fail in response to stress changes caused by hydrocarbon withdrawal. Sand production is generally undesirable since it causes a variety of problems ranging from significant safety risks during high-rate gas production, to the erosion of downhole equipment and surface facilities. It is widely accepted that a better understanding of the mechanics of poorly-consolidated formations is required to manage sand production; which, in turn, enables the cost effective production of gas and oil resources. In this work, a series of large-scale laboratory experiments was conducted in fully saturated, cohesionless sand layers to model the behavior of a petroleum reservoir near a wellbore. We directly observed several key characteristics of the sand production phenomenon including the formations of a stable cavity around the wellbore and a sub-radial flow channel at the upper surface of the tested layer. The flow channel is a first-order feature that appears to be a major part of the sand production mechanism. The channel cross section is orders of magnitude larger than the particle size, and once formed, the channel becomes the dominant conduit for fluid flow and particle transport. The flow channel developed in all of our experiments, and in all experiments, sand production continued from the developing channel after the cavity around the borehole stabilized. Our laboratory results constitute a well constrained data set that can be used to test and calibrate numerical models employed by the petroleum industry for predicting the sand production phenomenon. Although important for practical applications, real field cases are typically much less constrained. We used scaling considerations to develop a simple analytical model, constrained by our experimental results. We also simulated the behavior of a sand layer around a wellbore using two- and three-dimensional discrete element methods. It appears that the main sand production features observed in the laboratory experiments, can indeed be reproduced by means of discrete element modeling. Numerical results indicate that the cavity surface of repose is a key factor in the sand production mechanism. In particular, the sand particles on this surface are not significantly constrained. This lack of confinement reduces the flow velocity required to remove a particle, by many orders of magnitude. Also, the mechanism of channel development in the upper fraction of the sample can be attributed to subsidence of the formation due to lateral extension when an unconstrained cavity slope appears near the wellbore. This is substantiated by the erosion process and continued production of particles from the flow channel. The notion of the existence of this surface channel has the potential to scale up to natural reservoirs and can give insights into real-world sand production issues. It indicates a mechanism explaining why the production of particles does not cease in many petroleum reservoirs. Although the radial character of the fluid flow eventually stops sand production from the cavity near the wellbore, the production of particles still may continue from the propagating surface (interface) flow channel. The second topic of the thesis addresses factors affecting the geometry and, hence, the mechanical stability of caverns excavated in carbonate rock formations for natural gas storage. Storage facilities are required to store gas when supply exceeds demand during the winter months. In many places (such as New England or the Great Lakes region) where no salt domes are available to create gas storage caverns, it is possible to create cavities in limestone employing the acid injection method. In this method, carbonate rock is dissolved, while CO₂ and calcium chloride brine appear as products of the carbonate dissolution reactions. Driven by the density difference, CO₂ rises towards the ceiling whereas the brine sinks to the bottom of the cavern. A zone of mixed CO₂ , acid, and brine forms near the source of acid injection, whereas the brine sinks to the bottom of the cavern. Characterization of the cavern shape is required to understand stress changes during the cavity excavation, which can destabilize the cavern. It is also important to determine the location of the mixture-brine interface to select the place of acid injection. In this work, we propose to characterize the geometry of the cavern and the location of the mixture-brine interface by generating pressure waves in a pipe extending into the cavern, and measuring the reflected waves at various locations in another adjacent pipe. Conventional governing equations describe fluid transients in pipes loaded only by internal pressure (such as in the water hammer effect). To model the pressure wave propagation for realistic geometries, we derived new governing equations for pressure transients in pipes subjected to changes in both internal and external (confining) pressures. This is important because the internal pressure (used in the measurement) is changing in response to the perturbation of the external pressure when the pipe is contained in the cavern filled with fluids. If the pressure in the cavern is perturbed, the perturbation creates an internal pressure wave in the submerged pipe that has a signature of the cavern geometry. We showed that the classic equations are included in our formulation as a particular case, but they have limited validity for some practically important combinations of the controlling parameters. We linearized the governing equations and formulated appropriate boundary and initial conditions. Using a finite element method, we solved the obtained boundary value problem for a system of pipes and a cavern filled with various characteristic fluids such as aqueous acid, calcium chloride brine, and supercritical CO₂ . We found that the pressure waves of moderate amplitudes would create measurable pressure pulses in the submerged pipe. Furthermore, we determined the wavelengths required for resolving the cavern diameter from the pressure history. Our results suggest that the pressure transients technique can indeed be used for characterizing the geometry of gas storage caverns and locations of fluid interfaces in the acid injection method.
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Atilhan, Mert. "High accuracy p-rho-t measurements up to 200 MPa between 200 K and 500 K using a compact single sinker magnetic suspension densimeter for pure and natural gas like mixtures." [College Station, Tex. : Texas A&M University, 2007. http://hdl.handle.net/1969.1/ETD-TAMU-1903.

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Books on the topic "Natural gas Gas reservoirs. Thermodynamics"

1

Natural gas reservoir engineering. Malabar, Fla: Krieger Pub. Co., 1992.

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Klubova, T. T. Clayey reservoirs of oil and gas. New Delhi: Oxford & IBH Pub. Co., 1991.

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Klubova, T. T. Clayey reservoirs of oil and gas. Rotterdam: A.A. Balkema, 1991.

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North Sea Oil and Gas Reservoirs Seminar (1985 Trondheim, Norway). North sea oil and gas reservoirs: Proceedings of the North Sea Oil and Gas Reservoirs Seminar. London: Graham & Trotman for the Norwegian Institute of Technology, 1987.

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J, Economides Michael, ed. Advanced natural gas engineering. Houston, Tex: Gulf Pub., 2010.

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Dyman, T. S. The use of well-production data in quantifying gas-reservoir heterogeneity. Denver, CO: U.S. Dept. of the Interior, U.S. Geological Survey, 1998.

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Dyman, T. S. The use of well-production data in quantifying gas-reservoir heterogeneity. Denver, CO: U.S. Dept. of the Interior, U.S. Geological Survey, 1998.

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Dyman, T. S. The use of well-production data in quantifying gas-reservoir heterogeneity. Denver, CO: U.S. Dept. of the Interior, U.S. Geological Survey, 1998.

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Chengjie, Jing, ed. Songliao Pendi nan bu shen ceng you qi cang xing cheng yu fen bu. Beijing: Shi you gong ye chu ban she, 2010.

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Dyman, T. S. The use of well-production data in quantifying gas-reservoir heterogeneity. Denver, CO: U.S. Dept. of the Interior, U.S. Geological Survey, 1998.

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Book chapters on the topic "Natural gas Gas reservoirs. Thermodynamics"

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Collett, Timothy S. "A Review of Well-Log Analysis Techniques Used to Assess Gas-Hydrate-Bearing Reservoirs." In Natural Gas Hydrates, 189–210. Washington, D. C.: American Geophysical Union, 2013. http://dx.doi.org/10.1029/gm124p0189.

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Iijima, Azuma. "12. Zeolites in Petroleum and Natural Gas Reservoirs." In Natural Zeolites, edited by David L. Bish and Douglas W. Ming, 347–402. Berlin, Boston: De Gruyter, 2001. http://dx.doi.org/10.1515/9781501509117-014.

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Fasanino, Guy, and Jean-Eric Molinard. "Mechanism of Gas-Mater Flow in Storage Reservoirs." In Underground Storage of Natural Gas, 233–64. Dordrecht: Springer Netherlands, 1989. http://dx.doi.org/10.1007/978-94-009-0993-9_18.

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Corapcioglu, M. Yavuz, and Sorab Panday. "Fundamental Equations for Transport Processes in Storage Reservoirs." In Underground Storage of Natural Gas, 55–73. Dordrecht: Springer Netherlands, 1989. http://dx.doi.org/10.1007/978-94-009-0993-9_6.

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Shaw, D. C. "Numerical Simulation of Miscible Displacement Processes in Gas Storage Reservoirs." In Underground Storage of Natural Gas, 347–70. Dordrecht: Springer Netherlands, 1989. http://dx.doi.org/10.1007/978-94-009-0993-9_23.

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Tremblay, Alain, Jean Therrien, Bill Hamlin, Eva Wichmann, and Lawrence J. LeDrew. "GHG Emissions from Boreal Reservoirs and Natural Aquatic Ecosystems." In Greenhouse Gas Emissions — Fluxes and Processes, 209–32. Berlin, Heidelberg: Springer Berlin Heidelberg, 2005. http://dx.doi.org/10.1007/978-3-540-26643-3_9.

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Therrien, Jean, Alain Tremblay, and Robert B. Jacques. "CO2 Emissions from Semi-Arid Reservoirs and Natural Aquatic Ecosystems." In Greenhouse Gas Emissions — Fluxes and Processes, 233–50. Berlin, Heidelberg: Springer Berlin Heidelberg, 2005. http://dx.doi.org/10.1007/978-3-540-26643-3_10.

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van der Harst, A. C., and A. J. F. M. van Nieuwland. "Disposal of Carbon Dioxide in Depleted Natural Gas Reservoirs." In Climate and Energy: The Feasibility of Controlling CO2 Emissions, 178–88. Dordrecht: Springer Netherlands, 1989. http://dx.doi.org/10.1007/978-94-009-0485-9_11.

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Heffer, K. J., N. C. Last, N. C. Koutsabeloulis, H. C. M. Chan, M. Gutierrez, and A. Makurat. "The Influence of Natural Fractures, Faults and Earth Stresses on Reservoir Performance — Geomechanical Analysis by Numerical Modelling." In North Sea Oil and Gas Reservoirs — III, 201–11. Dordrecht: Springer Netherlands, 1994. http://dx.doi.org/10.1007/978-94-011-0896-6_16.

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Lambert, Maryse, and Jean-Louis Fréchette. "Analytical Techniques for Measuring Fluxes of CO2 and CH4 from Hydroelectric Reservoirs and Natural Water Bodies." In Greenhouse Gas Emissions — Fluxes and Processes, 37–60. Berlin, Heidelberg: Springer Berlin Heidelberg, 2005. http://dx.doi.org/10.1007/978-3-540-26643-3_3.

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Conference papers on the topic "Natural gas Gas reservoirs. Thermodynamics"

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Negara, Ardiansyah, Mokhtar Elgassier, and Bilal Saad. "Numerical Simulation of Natural Gas Flow in Shale Reservoirs with Thermodynamic Equation of State: A Comparative Study." In SPE Europec featured at 78th EAGE Conference and Exhibition. Society of Petroleum Engineers, 2016. http://dx.doi.org/10.2118/180095-ms.

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Fakher, Sherif, Youssef Elgahawy, Hesham Abdelaal, and Abdulmohsin Imqam. "What are the Dominant Flow Regimes During Carbon Dioxide Propagation in Shale Reservoirs’ Matrix, Natural Fractures and Hydraulic Fractures?" In SPE Western Regional Meeting. SPE, 2021. http://dx.doi.org/10.2118/200824-ms.

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Abstract Carbon dioxide (CO2) injection in low permeability shale reservoirs has recently gained much attention due to the claims that it has a large recovery factor and can also be used in CO2 storage operations. This research investigates the different flow regimes that the CO2 will exhibit during its propagation through the fractures, micropores, and the nanopores in unconventional shale reservoirs to accurately evaluate the mechanism by which CO2 recovers oil from these reservoirs. One of the most widely used tools to distinguish between different flow regimes is the Knudsen Number. Initially, a mathematical analysis of the different flow regimes that can be observed in pore sizes ranging between 0.2 nanometer and more than 2 micrometers was undergone at different pressure and temperature conditions to distinguish between the different flow regimes that the CO2 will exhibit in the different pore sizes. Based on the results, several flow regime maps were conducted for different pore sizes. The pore sizes were grouped together in separate maps based on the flow regimes exhibited at different thermodynamic conditions. Based on the results, it was found that Knudsen diffusion dominated the flow regime in nanopores ranging between 0.2 nanometers, up to 1 nanometer. Pore sizes between 2 and 10 nanometers were dominated by both a transition flow, and slip flow. At 25 nanometer, and up to 100 nanometers, three flow regimes can be observed, including gas slippage flow, transition flow, and viscous flow. When the pore size reached 150 nanometers, Knudsen diffusion and transition flow disappeared, and the slippage and viscous flow regimes were dominant. At pore sizes above one micrometer, the flow was viscous for all thermodynamic conditions. This indicated that in the larger pore sizes the flow will be mainly viscous flow, which is usually modeled using Darcy's law, while in the extremely small pore sizes the dominating flow regime is Knudsen diffusion, which can be modeled using Knudsen's Diffusion law or in cases where surface diffusion is dominant, Fick's law of diffusion can be applied. The mechanism by which the CO2 improves recovery in unconventional shale reservoirs is not fully understood to this date, which is the main reason why this process has proven successful in some shale plays, and failed in others. This research studies the flow behavior of the CO2 in the different features that could be present in the shale reservoir to illustrate the mechanism by which oil recovery can be increased.
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Aimoli, Cassiano G., Danilo P. de Carvalho, Pedro A. P. Filho, and Edward J. Maginn. "Thermodynamic Properties and Fluid Phase Equilibria of Natural Gas Containing CO2 and H2O at Extreme Pressures for Injection in the Brazilian Pre-Salt Reservoirs." In OTC Brasil. Offshore Technology Conference, 2017. http://dx.doi.org/10.4043/28117-ms.

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Čarnogurská, Mária, and Miroslav Příhoda. "Impact of exhaust gas recirculation on production of nitrogen oxides in natural gas combustion." In 37TH MEETING OF DEPARTMENTS OF FLUID MECHANICS AND THERMODYNAMICS. Author(s), 2018. http://dx.doi.org/10.1063/1.5049910.

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Northrop, D. A. "Insights Into Natural Gas Production From Low-Permeability Reservoirs." In SPE Gas Technology Symposium. Society of Petroleum Engineers, 1988. http://dx.doi.org/10.2118/17706-ms.

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Ayala H., Luis Felipe, and Peng Ye. "Analysis of Unsteady Responses of Natural Gas Reservoirs via a Universal Natural Gas Type-Curve Formulation." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2012. http://dx.doi.org/10.2118/159956-ms.

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Uddin, Mafiz, Fred Wright, and Dennis Allan Coombe. "Numerical Study of Gas Evolution and Transport Behaviors in Natural Gas Hydrate Reservoirs." In Canadian Unconventional Resources and International Petroleum Conference. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/137439-ms.

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Aguilera, Roberto. "Role of Natural Fractures and Slot Porosity on Tight Gas Sands." In SPE Unconventional Reservoirs Conference. Society of Petroleum Engineers, 2008. http://dx.doi.org/10.2118/114174-ms.

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Figueira, Brendan Marcus, Jill K. Marcelle-De Silva, Wanda-Lee DeLandro-Clarke, and Wayne Gerrard Bertrand. "The Occurrence of Unconventional Natural Gas Reservoirs Offshore Trinidad." In Trinidad and Tobago Energy Resources Conference. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/133531-ms.

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Masanobu, Sotaro, Shunji Kato, Arata Nakamura, Takashi Sakamoto, Toshio Yoshikawa, Atsushi Sakamoto, Hideo Uetani, Kenichi Kawazuishi, and Kunihisa Sao. "Development of Natural Gas Liquefaction FPSO." In ASME 2004 23rd International Conference on Offshore Mechanics and Arctic Engineering. ASMEDC, 2004. http://dx.doi.org/10.1115/omae2004-51382.

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Natural gas is abundant and is cleaner than petroleum. Therefore, demand for natural gas is expected to grow significantly. However, the means of transporting natural gas is presently limited to pipelines and LNG tankers, thereby making its wider use unlikely. There are substantial numbers of known gas reservoirs that are difficult to develop utilizing current transportation means because of constraints such as the scale of gas fields, water depth, distance to shore, and distance from markets. A new, economical, reliable development technique or transportation means is required for developing such gas reservoirs. Ministry of Economy, Trade and Industry (METI), Japan National Oil Corporation (JNOC) and private corporations have jointly investigated the Natural Gas Liquefaction Floating Production, Storage and Offloading (NGL-FPSOs) units to effectively develop gas reservoirs by converting the gas into NGL. This paper presents the background on NGL-FPSO development and findings on its application.
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Reports on the topic "Natural gas Gas reservoirs. Thermodynamics"

1

Maria Cecilia Bravo. Production of Natural Gas and Fluid Flow in Tight Sand Reservoirs. Office of Scientific and Technical Information (OSTI), June 2006. http://dx.doi.org/10.2172/908661.

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Maria Cecilia Bravo and Mariano Gurfinkel. Production of Natural Gas and Fluid Flow in Tight Sand Reservoirs. Office of Scientific and Technical Information (OSTI), June 2005. http://dx.doi.org/10.2172/897805.

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Freifeld, Barry, Curtis Oldenburg, Preston Jordan, Lehua Pan, Scott Perfect, Joseph Morris, Joshua White, et al. Well Integrity for Natural Gas Storage in Depleted Reservoirs and Aquifers. Office of Scientific and Technical Information (OSTI), September 2016. http://dx.doi.org/10.2172/1431465.

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Bauer, Stephen J., Douglas A. Blankenship, Barry L. Roberts, Barry Freifeld, Scott Perfect, Grant Bromhal, Curtis Oldenburg, et al. Well Integrity for Natural Gas Storage in Depleted Reservoirs and Aquifers. Office of Scientific and Technical Information (OSTI), January 2017. http://dx.doi.org/10.2172/1432270.

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Freifeld, Barry M., Curtis M. Oldenburg, Preston Jordan, Lehua Pan, Scott Perfect, Joseph Morris, Joshua White, et al. Well Integrity for Natural Gas Storage in Depleted Reservoirs and Aquifers. Office of Scientific and Technical Information (OSTI), September 2016. http://dx.doi.org/10.2172/1338936.

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Cooper, Paul W., Mark Charles Grubelich, and Stephen J. Bauer. Potential hazards of compressed air energy storage in depleted natural gas reservoirs. Office of Scientific and Technical Information (OSTI), September 2011. http://dx.doi.org/10.2172/1029814.

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Heath, Jason E., Kristopher L. Kuhlman, David G. Robinson, Stephen J. Bauer, and William Payton Gardner. Appraisal of transport and deformation in shale reservoirs using natural noble gas tracers. Office of Scientific and Technical Information (OSTI), September 2015. http://dx.doi.org/10.2172/1222657.

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Gardner, William Payton. Preliminary formation analysis for compressed air energy storage in depleted natural gas reservoirs :. Office of Scientific and Technical Information (OSTI), June 2013. http://dx.doi.org/10.2172/1089981.

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Mark E. Willis, Daniel R. Burns, and M. Nafi Toksoz. Natural and Induced Fracture Diagnostics from 4-D VSP Low Permeability Gas Reservoirs. Office of Scientific and Technical Information (OSTI), September 2008. http://dx.doi.org/10.2172/963893.

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J.H. Frantz and K.G. Brown. CHARACTERIZATION OF CONDITIONS OF NATURAL GAS STORAGE RESERVOIRS AND DESIGN AND DEMONSTRATION OF REMEDIAL TECHNIQUES FOR DAMAGE MECHANISMS FOUND THEREIN. Office of Scientific and Technical Information (OSTI), February 2003. http://dx.doi.org/10.2172/823178.

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