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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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Carpenter, Chris. "Natural-Gas-Foam Fluid Reduces Water Needed for Fracture Stimulations." Journal of Petroleum Technology 73, no. 06 (June 1, 2021): 56–57. http://dx.doi.org/10.2118/0621-0056-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201450, “Reducing the Volume of Water Needed For Hydraulic Fracturing by Using Natural-Gas-Foamed Stimulation Fluid,” by Raj Malpani, SPE, Chris Daeffler, and Sandeep Verma, SPE, Schlumberger, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Using natural-gas (NG) -foam fracturing fluids reduces the enormous water requirements for stimulation by as much as 60 to 80% and poses benefits for productivity in water-sensitive formations. The study outlined in the complete paper aims to characterize hydraulic-fracture geometry and quantify the expected production when using an NG-foam fracturing fluid. Using validated models, the authors provide a comparative analysis to determine the advantages of using NG foams relative to conventionally used slickwater, linear gel, and crosslinked fluid. NG-Foam Fluids Although foamed fluids were first used in the 1960s, the use of nitrogen (N2) and carbon dioxide (CO2) foams has not been widely practiced because of cost, complexity, and unproven production benefits. The use of NG-foam fracturing fluid is not widespread either, but this study attempts to identify specific regions and reservoirs where the use of these fluids may lead to economic and long-term production benefits. The authors write that using NG foams is likely to provide long-term sustainable benefits in areas where water procurement and disposal costs are high, where natural gas may be available from a central processing facility through pipelines, and where the reservoir is relatively shallow and contains clay-bearing minerals. This work is inspired by a program sponsored by the US Department of Energy to investigate NG as an alternative to N2 and CO2 in foamed fracturing fluids. Initially, the project focused on identifying a thermodynamic path-way to use NG obtained from producing wells and processing plants. The study later extended into laboratory-scale experiments to measure NG-foam-fluid rheology, which was found to be comparable to foams based on N2 and CO2. The first step in the work flow is to build a static geological model to capture the reservoir description. The subsequent step is to use the rock characterization to simulate the induced hydraulic fractures. The hydraulic-fracture simulator also predicts the proppant distribution and its conductivity and treating pressure. The simulated treating pressure is matched with observed pressure during stimulation treatment to calibrate the hydraulic-fracture model. The hydraulic fractures are then gridded in the static geological model to generate the reservoir model for flow modeling. This is a critical step in the process because the static model is linked to the dynamic simulator without losing the details of the hydraulic fractures. The reservoir simulator is used to match the historical production performance to calibrate the reservoir model and forecast future production profiles. This hydraulic-fracture modeling, followed by the flow-modeling process, is repeated for various pumping schedules and recipes to perform a sensitivity analysis, which is detailed in the complete paper.
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Igboanusi, U. P., and J. U. Okere. "Natural Gas Hydrates – A Review of the Resources Offshore Nigeria and around the Globe." International Journal of Engineering Research in Africa 4 (May 2011): 27–33. http://dx.doi.org/10.4028/www.scientific.net/jera.4.27.
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Natural gas hydrates are ice-like materials which exist in permafrost regions and in the continental margins of oceans. They constitute a huge unconventional reservoir of natural gas around the globe including offshore Nigeria. The paper is a review of this important global resource with particular focus on the Nigerian deposits. The reasons for the interest on hydrates are discussed including the potential for the recovery of large quantities of methane, the climate change and ocean floor instability that may result from their dissociation. They may also be exploited for large-scale CO2 sequestration. The geographical distribution of hydrates deposits on earth, the thermodynamics of why they occur in those particular places and source of the methane gas that is eventually enchlathrated into hydrates are discussed. The natural gas in the Nigerian hydrate is essentially biogenic in origin and is almost pure methane (more than 99% methane). The hydrates exist in finely disseminated or massive aggregate forms within clay-rich sediment.
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Graue, Arne, B. Kvamme, Bernie Baldwin, Jim Stevens, James J. Howard, Eirik Aspenes, Geir Ersland, Jarle Husebo, and D. Zornes. "MRI Visualization of Spontaneous Methane Production From Hydrates in Sandstone Core Plugs When Exposed to CO2." SPE Journal 13, no. 02 (June 1, 2008): 146–52. http://dx.doi.org/10.2118/118851-pa.
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Summary Magnetic resonance imaging (MRI) of core samples in laboratory experiments showed that CO2 storage in gas hydrates formed in porous rock resulted in the spontaneous production of methane with no associated water production. The exposure of methane hydrate in the pores to liquid CO2 resulted in methane production from the hydrate that suggested the exchange of methane molecules with CO2 molecules within the hydrate without the addition or subtraction of significant amounts of heat. Thermodynamic simulations based on Phase Field Theory were in agreement with these results and predicted similar methane production rates that were observed in several experiments. MRI-based 3D visualizations of the formation of hydrates in the porous rock and the methane production improved the interpretation of the experiments. The sequestration of an important greenhouse gas while simultaneously producing the freed natural gas offers access to the significant amounts of energy bound in natural gas hydrates and also offers an attractive potential for CO2 storage. The potential danger associated with catastrophic dissociation of hydrate structures in nature and the corresponding collapse of geological formations is reduced because of the increased thermodynamic stability of the CO2 hydrate relative to the natural gas hydrate. Introduction The replacement of methane in natural gas hydrates with CO2 presents an attractive scenario of providing a source of abundant natural gas while establishing a thermodynamically more stable hydrate accumulation. Natural gas hydrates represent an enormous potential energy source as the total energy corresponding to natural gas entrapped in hydrate reservoirs is estimated to be more than twice the energy of all known energy sources of coal, oil, and gas (Sloan 2003). Thermodynamic stability of the hydrate is sensitive to local temperature and pressure, but all components in the hydrate have to be in equilibrium with the surroundings if the hydrate is to be thermodynamically stable. Natural gas hydrate accumulations are therefore rarely in a state of complete stability in a strict thermodynamic sense. Typically, the hydrate associated with fine-grain sediments is trapped between low-permeability layers that keep the system in a state of very slow dynamics. One concern of hydrate dissociation, especially near the surface of either submarine or permafrost-associated deposits, is the potential for the release of methane to the water column or atmosphere. Methane represents an environmental concern because it is a more aggressive (~25 times) greenhouse gas than CO2. A more serious concern is related to the stability of these hydrate formations and its impact on the surrounding sediments. Changes in local conditions of temperature, pressure, or surrounding fluids can change the dynamics of the system and lead to catastrophic dissociation of the hydrates and consequent sediment instability. The Storegga mudslide in offshore Norway was created by several catastrophic hydrate dissociations. The largest of these was estimated to have occurred 7,000 years ago and was believed to have created a massive tsunami (Dawson et al. 1988). The replacement of natural gas hydrate with CO2 hydrate has the potential to increase the stability of hydrate-saturated sediments under near-surface conditions. Hydrocarbon exploitation in hydrate-bearing regions has the additional challenge to drilling operations of controlling heat production from drilling and its potential risk of local hydrate dissociation (Yakushev and Collett 1992). The molar volume of hydrate is 25-30% greater than the volume of liquid water under the same temperature-pressure conditions. Any production scenario for natural gas hydrate that involves significant dissociation of the hydrate (e.g., pressure depletion) has to account for the release of significant amounts of water that in turn affects the local mechanical stress on the reservoir formation. In the worst case, this would lead to local collapse of the surrounding formation. Natural gas production by CO2 exchange and sequestration benefits from the observation that there is little or no associated liquid water production during this process. Production of gas by hydrate dissociation can produce large volumes of associated water, and can create a significant environmental problem that would severely limit the economic potential. The conversion from methane hydrate to a CO2 hydrate is thermodynamically favorable in terms of free energy differences, and the phase transition is coupled to corresponding processes of mass and heat transport. The essential question is then if it is possible to actually convert methane hydrate as found in sediments to CO2 hydrate. Experiments that formed natural gas hydrates in porous sandstone core plugs used MRI to monitor the dynamics of hydrate formation and reformation. The paper emphasizes the experimental procedures developed to form the initial natural gas hydrates in sandstone pores and the subsequent exchange with CO2 while monitoring the dynamic process with 3D imaging on a sub millimetre scale. The in-situ imaging illustrates the production of methane from methane hydrate when exposed to liquid CO2 without any external heating.
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Kvamme, Bjørn. "Feasibility of simultaneous CO2 storage and CH4 production from natural gas hydrate using mixtures of CO2 and N2." Canadian Journal of Chemistry 93, no. 8 (August 2015): 897–905. http://dx.doi.org/10.1139/cjc-2014-0501.
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Production of natural gas from hydrate using carbon dioxide allows for a win-win situation in which carbon dioxide can be safely stored in hydrate form while releasing natural gas from in situ hydrate. This concept has been verified experimentally and theoretically in different laboratories worldwide, and lately also in a pilot plant in Alaska. The use of carbon dioxide mixed with nitrogen has the advantage of higher gas permeability. Blocking of flow channels due to formation of new hydrate from injected gas will also be less compared to injection of pure carbon dioxide. The fastest mechanism for conversion involves the formation of a new hydrate from free pore water and the injected gas. As a consequence of the first and second laws of thermodynamics, the most stable hydrate will form first in a dynamic situation, in which carbon dioxide will dominate the first hydrates formed from water and carbon dioxide / nitrogen mixtures. This selective formation process is further enhanced by favorable selective adsorption of carbon dioxide onto mineral surfaces as well as onto liquid water surfaces, which facilitates efficient heterogeneous hydrate nucleation. In this work we examine limitations of hydrate stability as function of gradually decreasing content of carbon dioxide. It is argued that if the flux of gas through the reservoir is high enough to prevent the gas from being depleted for carbon dioxide prior to subsequent supply of new gas, then the combined carbon dioxide storage and natural gas production is still feasible. Otherwise the residual gas dominated by nitrogen will still dissociate the methane hydrate, if the released in situ CH4 from hydrate does not mix in with the gas but escapes through separate flow channels by buoyancy. The ratio of nitrogen to carbon dioxide in such mixtures is therefore a sensitive balance between flow rates and formation rates of new carbon dioxide dominated hydrate. Hydrate instability due to undersaturations of hydrate formers have not been discussed in this work but might add additional instability aspects.
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Nasrabadi, Hadi, Kassem Ghorayeb, and Abbas Firoozabadi. "Two-Phase Multicomponent Diffusion and Convection for Reservoir Initialization." SPE Reservoir Evaluation & Engineering 9, no. 05 (October 1, 2006): 530–42. http://dx.doi.org/10.2118/66365-pa.
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Summary We present formulation and numerical solution of two-phase multicomponent diffusion and natural convection in porous media. Thermal diffusion, pressure diffusion, and molecular diffusion are included in the diffusion expression from thermodynamics of irreversible processes. The formulation and the numerical solution are used to perform initialization in a 2D cross section. We use both homogeneous and layered media without and with anisotropy in our calculations. Numerical examples for a binary mixture of C1/C3 and a multicomponent reservoir fluid are presented. Results show a strong effect of natural convection in species distribution. Results also show that there are at least two main rotating cells at steady state: one in the gas cap, and one in the oil column. Introduction Proper initialization is an important aspect of reliable reservoir simulations. The use of the Gibbs segregation condition generally cannot provide reliable initialization in hydrocarbon reservoirs. This is caused, in part, by the effect of thermal diffusion (caused by the geothermal temperature gradient), which cannot be neglected in some cases; thermal diffusion might be the main phenomenon affecting compositional variation in hydrocarbon reservoirs, especially for near-critical gas/condensate reservoirs (Ghorayeb et al. 2003). Generally, temperature increases with increasing burial depth because heat flows from the Earth's interior toward the surface. The temperature profile, or geothermal gradient, is related to the thermal conductivity of a body of rock and the heat flux. Thermal conductivity is not necessarily uniform because it depends on the mineralogical composition of the rock, the porosity, and the presence of water or gas. Therefore, differences in thermal conductivity between adjacent lithologies can result in a horizontal temperature gradient. Horizontal temperature gradients in some offshore fields can be observed because of a constant water temperature (approximately 4°C) in different depths in the seabed floor. The horizontal temperature gradient causes natural convection that might have a significant effect on species distribution (Firoozabadi 1999). The combined effects of diffusion (pressure, thermal, and molecular) and natural convection on compositional variation in multicomponent mixtures in porous media have been investigated for single-phase systems (Riley and Firoozabadi 1998; Ghorayeb and Firoozabadi 2000a).The results from these references show the importance of natural convection, which, in some cases, overrides diffusion and results in a uniform composition. Natural convection also can result in increased horizontal compositional variation, an effect similar to that in a thermogravitational column (Ghorayeb and Firoozabadi 2001; Nasrabadi et al. 2006). The combined effect of convection and diffusion on species separation has been the subject of many experimental studies. Separation in a thermogravitational column with both effects has been measured widely (Schott 1973; Costeseque 1982; El Mataaoui 1986). The thermogravitational column consists of two isothermal vertical plates with different temperatures separated by a narrow space. The space can be either without a porous medium or filled with a porous medium. The thermal diffusion, in a binary mixture, causes one component to segregate to the hot plate and the other to the cold plate. Because of the density gradient caused by temperature and concentration gradients, convection flow occurs and creates a concentration difference between the top and bottom of the column. Analytical and numerical models have been presented to analyze the experimental results (Lorenz and Emery 1959; Jamet et al. 1992; Nasrabadi et al. 2006). The experimental and theoretical studies show that the composition difference between the top and bottom of the column increases with permeability until an optimum permeability is reached. Then, the composition difference declines as permeability increases. The process in a thermogravitational column shows the significance of the convection from a horizontal temperature gradient.
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Pandey, Jyoti Shanker, Charilaos Karantonidis, Adam Paul Karcz, and Nicolas von Solms. "Enhanced CH4-CO2 Hydrate Swapping in the Presence of Low Dosage Methanol." Energies 13, no. 20 (October 9, 2020): 5238. http://dx.doi.org/10.3390/en13205238.
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CO2-rich gas injection into natural gas hydrate reservoirs is proposed as a carbon-neutral, novel technique to store CO2 while simultaneously producing CH4 gas from methane hydrate deposits without disturbing geological settings. This method is limited by the mass transport barrier created by hydrate film formation at the liquid–gas interface. The very low gas diffusivity through hydrate film formed at this interface causes low CO2 availability at the gas–hydrate interface, thus lowering the recovery and replacement efficiency during CH4-CO2 exchange. In a first-of-its-kind study, we have demonstrate the successful application of low dosage methanol to enhance gas storage and recovery and compare it with water and other surface-active kinetic promoters including SDS and L-methionine. Our study shows 40–80% CH4 recovery, 83–93% CO2 storage and 3–10% CH4-CO2 replacement efficiency in the presence of 5 wt% methanol, and further improvement in the swapping process due to a change in temperature from 1–4 °C is observed. We also discuss the influence of initial water saturation (30–66%), hydrate morphology (grain-coating and pore-filling) and hydrate surface area on the CH4-CO2 hydrate swapping. Very distinctive behavior in methane recovery caused by initial water saturation (above and below Swi = 0.35) and hydrate morphology is also discussed. Improved CO2 storage and methane recovery in the presence of methanol is attributed to its dual role as anti-agglomerate and thermodynamic driving force enhancer between CH4-CO2 hydrate phase boundaries when methanol is used at a low concentration (5 wt%). The findings of this study can be useful in exploring the usage of low dosage, bio-friendly, anti-agglomerate and hydrate inhibition compounds in improving CH4 recovery and storing CO2 in hydrate reservoirs without disturbing geological formation. To the best of the authors’ knowledge, this is the first experimental study to explore the novel application of an anti-agglomerate and hydrate inhibitor in low dosage to address the CO2 hydrate mass transfer barrier created at the gas–liquid interface to enhance CH4-CO2 hydrate exchange. Our study also highlights the importance of prior information about methane hydrate reservoirs, such as residual water saturation, degree of hydrate saturation and hydrate morphology, before applying the CH4-CO2 hydrate swapping technique.
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Bhawangirkar, Dnyaneshwar R., Vishnu Chandrasekharan Nair, Siddhant Kumar Prasad, and Jitendra S. Sangwai. "Natural Gas Hydrates in the Krishna-Godavari Basin Sediments under Marine Reservoir Conditions: Thermodynamics and Dissociation Kinetics using Thermal Stimulation." Energy & Fuels 35, no. 10 (May 11, 2021): 8685–98. http://dx.doi.org/10.1021/acs.energyfuels.1c00162.
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Aimoli, Cassiano G., Danilo P. de Carvalho, Pedro A. Pessoa Filho, Edward J. Maginn, and Charlles R. A. Abreu. "Thermodynamic properties and fluid phase equilibrium of natural gas containing CO2 and H2O at extreme pressures typically found in pre-salt reservoirs." Journal of Natural Gas Science and Engineering 79 (July 2020): 103337. http://dx.doi.org/10.1016/j.jngse.2020.103337.
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Kvamme, Bjørn, Jinzhou Zhao, Na Wei, and Navid Saeidi. "Hydrate—A Mysterious Phase or Just Misunderstood?" Energies 13, no. 4 (February 17, 2020): 880. http://dx.doi.org/10.3390/en13040880.
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Hydrates that form during transport of hydrocarbons containing free water, or water dissolved in hydrocarbons, are generally not in thermodynamic equilibrium and depend on the concentration of all components in all phases. Temperature and pressure are normally the only variables used in hydrate analysis, even though hydrates will dissolve by contact with pure water and water which is under saturated with hydrate formers. Mineral surfaces (for example rust) play dual roles as hydrate inhibitors and hydrate nucleation sites. What appears to be mysterious, and often random, is actually the effects of hydrate non-equilibrium and competing hydrate formation and dissociation phase transitions. There is a need to move forward towards a more complete non-equilibrium way to approach hydrates in industrial settings. Similar challenges are related to natural gas hydrates in sediments. Hydrates dissociates worldwide due to seawater that leaks into hydrate filled sediments. Many of the global resources of methane hydrate reside in a stationary situation of hydrate dissociation from incoming water and formation of new hydrate from incoming hydrate formers from below. Understanding the dynamic situation of a real hydrate reservoir is critical for understanding the distribution characteristics of hydrates in the sediments. This knowledge is also critical for designing efficient hydrate production strategies. In order to facilitate the needed analysis we propose the use of residual thermodynamics for all phases, including all hydrate phases, so as to be able to analyze real stability limits and needed heat supply for hydrate production.
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Pa´dua, K. G. O. "Nonisothermal Gravitational Equilibrium Model." SPE Reservoir Evaluation & Engineering 2, no. 02 (April 1, 1999): 211–17. http://dx.doi.org/10.2118/55972-pa.
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Summary This work presents a new computational model for the non-isothermal gravitational compositional equilibrium. The works of Bedrikovetsky [Mathemathical Theory of Oil and Gas Recovery, Kluwer Academic Publishers, London, (1993)] (gravity and temperature) and of Whitson and Belery ("Compositional Gradients in Petroleum Reservoirs," paper SPE 28000, presented at the 1994 University of Tulsa Centennal Petroleum Engineering Symposium, Tulsa, 29-31 August) (algorithm) are the basis of the mathematical formulation. Published data and previous simplified models validate the computational procedure. A large deep-water field in Campos Basin, Brazil, exemplifies the practical application of the model. The field has an unusual temperature gradient opposite to the Earth's thermal gradient. The results indicate the increase of oil segregation with temperature decrease. The application to field data suggests the reservoir could be partially connected. Fluid composition and property variation are extrapolated to different depths with its respective temperatures. The work is an example of the application of thermodynamic data to the evaluation of reservoir connectivity and fluid properties distribution. Problem Compositional variations along the hydrocarbon column are observed in many reservoirs around the world.1–4 They may affect reservoir/fluid characteristics considerably leading to different field development strategies.5 These variations are caused by many factors, such as gravity, temperature gradient, rock heterogeneity, hydrocarbon genesis and accumulation processes.6 In cases where thermodynamic associated factors (gravity and temperature) are dominant (mixing process in the secondary migration), existing gravitational compositional equilibrium (GCE) models7,8 provide an explanation of most observed variations. However, in some cases8,9 the thermal effect could have the same order of magnitude as the gravity effect. The formulation for calculating compositional variation under the force of gravity for an isothermal system was first given by Gibbs10 $$\mu {ci}(p, Z, T)=\mu {i}(p {{\rm ref}}, Z {{\rm ref}}, T {{\rm ref}}) - m {i}g(h - h {{\rm ref}}),\eqno ({\rm 1})$$ $$\mu {ci}=\delta [nRT\,{\rm ln}(f {i})]/\delta x,\eqno ({\rm 2})$$ $$f {i}=f({\rm EOS}),\eqno ({\rm 3})$$where p =pressure, T=temperature, Z=fluid composition, m=mass, ? c=chemical potential, h=depth, ref=reference, EOS=equation of state, i=component indices, R=real gas constant, n=number of moles, f=fugacity, ln=natural logarithm, x=component concentration, and g=gravitational acceleration. In 1930 Muskat11 provided an exact solution to Eq. (1), assuming a simplified equation of state and ideal mixing. Because of the oversimplified assumptions, the results suggest that gravity has a negligible effect on the compositional variation in reservoir systems. In 1938, Sage and Lacey12 used a more realistic equation of state (EOS), Eq. (3), to evaluate Eq. (2). At that time, the results showed significant composition variations with depth and greater ones for systems close to critical conditions. Schulte13 solved Eq. (1) using a cubic equation of state (3) in 1980. The results showed significant compositional variations. They also suggested a significant effect of the interaction coefficients and the aromatic content of the oil as well as a negligible effect of the EOS type (Peng-Robinson and Soave-Redlich-Kwong) on the final results. A simplified formulation that included gravity and temperature separately was presented by Holt et al.9 in 1983. Example calculations, limited to binary systems, suggest that thermal effects can be of the same magnitude as gravity effects. In 1988, Hirschberg5 discussed the influence of asphaltenes on compositional grading using a simplified two component model (asphaltenes and non-asphaltenes). He concluded, that for oils with oil gravity <35°API, the compositional variations are mainly caused by asphalt segregation and the most important consequences are the large variations in oil viscosity and the possible formation of tar mats. Montel and Gouel7 presented an algorithm in 1985 for solving the GCE problem using an incremental hydrostatic term instead of solving for pressure directly. Field case applications of GCE models were presented by Riemens et al.2 in 1985, and by Creek et al.1 in 1988. They reported some difficulties in matching observed and calculated data but, in the end, it was shown that most compositional variations could be explained by the effect of gravity. Wheaton14 and Lee6 presented GCE models that included capillary forces in 1988 and 1989, respectively. Lee concluded that the effect of capillarity can become appreciable in the neighborhood of 1 ?m pore radius. In 1990, an attempt to combine the effects of gravity and temperature for a system of zero net mass flux was presented by Belery and Silva.15 The multicomponent model was an extension of earlier work by Dougherty and Drickamer16 that was originally developed in 1955 for binary liquid systems. The comparison of calculated and observed data from Ekofisk field in the North Sea is, however, not quantitatively accurate (with or without thermal effect). An extensive discussion and the formal mathematical treatment of compositional grading using irreversible thermodynamics, including gravitational and thermal fields, was presented by Bedrikovetsky17 in 1993. Due to the lack of necessary information on the values of thermal diffusion coefficients, which in general are obtained experimentally only for certain mixtures in narrow ranges of pressure and temperature, simplified models were proposed. In 1994, Hamoodi and Abed3 presented a field case of a giant Middle East reservoir with areal and vertical variations in its composition.
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Kerčmar, Jernej. "Natural gas reservoirs on the oil-gas field Petišovci." Geologija 61, no. 2 (December 21, 2018): 163–76. http://dx.doi.org/10.5474/geologija.2018.011.
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Ramoutar, S., and C. Riverol. "A thermodynamic analysis of refueling a Natural Gas Vehicle cylinder from a cascade reservoir using chilled natural gas." Journal of Natural Gas Science and Engineering 38 (February 2017): 298–322. http://dx.doi.org/10.1016/j.jngse.2016.12.019.
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Maksimov, A. M., and G. G. Tsypkin. "Dissociation of gas hydrates coexisting with gas in natural reservoirs." Fluid Dynamics 25, no. 5 (1991): 719–23. http://dx.doi.org/10.1007/bf01049542.
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Gord, Mahmood Farzaneh, Mahdi Deymi Dashtebayaz, and Hamid Reza Rahbari. "Optimising Compressed Natural Gas filling stations reservoir pressure based on thermodynamic analysis." International Journal of Exergy 10, no. 3 (2012): 299. http://dx.doi.org/10.1504/ijex.2012.046836.
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Dong, Hao, Yi Zhang, Zongwu Li, Chao Jiang, Jiaze Li, Tao Wu, Liting Wang, et al. "Model Optimization of Shale Gas Reservoir Volume Fracturing Dissolved Gas Simulation Adsorbed Gas." Geofluids 2021 (February 18, 2021): 1–15. http://dx.doi.org/10.1155/2021/6631994.
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Shale reservoirs have some natural fractures with a certain density and connectivity. The basic percolation model of shale gas reservoir: the black oil model of gas-water phase is used as the basic model, and the dissolved gas is used to simulate adsorbed gas. Accurate description of natural fractures: random distributed discrete fracture model is used as the basic model to describe natural fractures. By comparing the calculation results of single medium (including random distributed discrete fracture model) and double medium model, the model for predicting shale gas productivity is optimized.
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Das, Jitendra. "Extracting Natural Gas Through Desorption in Shale Reservoirs." Way Ahead 08, no. 01 (February 1, 2012): 11–13. http://dx.doi.org/10.2118/0112-011-twa.
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Vinegar, Harold J., Ridva Akkurt, and Pierre N. Tutunjian. "5498960 NMR logging of natural gas in reservoirs." Magnetic Resonance Imaging 14, no. 9 (January 1996): VII. http://dx.doi.org/10.1016/s0730-725x(97)87347-x.
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Kondrat, Oleksandr, and Nazarìj Gedzik. "Enhanced natural gas recovery from low-permeable reservoirs." AGH Drilling, Oil, Gas 33, no. 2 (2016): 323. http://dx.doi.org/10.7494/drill.2016.33.2.323.
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Bahrami, Hassan, Reza Rezaee, and Mofazzal Hossain. "Characterizing natural fractures productivity in tight gas reservoirs." Journal of Petroleum Exploration and Production Technology 2, no. 2 (July 2012): 107–15. http://dx.doi.org/10.1007/s13202-012-0026-x.
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Prausnitz, J. M., and R. L. Cotterman. "Application of Continuous Thermodynamics to Natural-Gas Mixtures." Revue de l'Institut Français du Pétrole 45, no. 5 (September 1990): 633–43. http://dx.doi.org/10.2516/ogst:1990040.
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Uddin, Mafiz, Fred Wright, and Dennis A. Coombe. "Numerical Study of Gas Evolution and Transport Behaviours in Natural Gas-Hydrate Reservoirs." Journal of Canadian Petroleum Technology 50, no. 01 (January 1, 2011): 70–89. http://dx.doi.org/10.2118/137439-pa.
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Galli, Federico, Jun-Jie Lai, Jacopo De Tommaso, Gianluca Pauletto, and Gregory S. Patience. "Gas to Liquids Techno-Economics of Associated Natural Gas, Bio Gas, and Landfill Gas." Processes 9, no. 9 (September 1, 2021): 1568. http://dx.doi.org/10.3390/pr9091568.
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Methane is the second highest contributor to the greenhouse effect. Its global warming potential is 37 times that of CO2. Flaring-associated natural gas from remote oil reservoirs is currently the only economical alternative. Gas-to-liquid (GtL) technologies first convert natural gas into syngas, then it into liquids such as methanol, Fischer–Tropsch fuels or dimethyl ether. However, studies on the influence of feedstock composition are sparse, which also poses technical design challenges. Here, we examine the techno-economic analysis of a micro-refinery unit (MRU) that partially oxidizes methane-rich feedstocks and polymerizes the syngas formed via Fischer–Tropsch reaction. We consider three methane-containing waste gases: natural gas, biogas, and landfill gas. The FT fuel selling price is critical for the economy of the unit. A Monte Carlo simulation assesses the influence of the composition on the final product quantity as well as on the capital and operative expenses. The Aspen Plus simulation and Python calculate the net present value and payback time of the MRU for different price scenarios. The CO2 content in biogas and landfill gas limit the CO/H2 ratio to 1.3 and 0.9, respectively, which increases the olefins content of the final product. Compressors are the main source of capital cost while the labor cost represents 20–25% of the variable cost. An analysis of the impact of the plant dimension demonstrated that the higher number represents a favorable business model for this unit. A minimal production of 7,300,000 kg y−1 is required for MRU to have a positive net present value after 10 years when natural gas is the feedstock.
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Thiagarajan, Nivedita, Hao Xie, Camilo Ponton, Nami Kitchen, Brian Peterson, Michael Lawson, Michael Formolo, Yitian Xiao, and John Eiler. "Isotopic evidence for quasi-equilibrium chemistry in thermally mature natural gases." Proceedings of the National Academy of Sciences 117, no. 8 (February 11, 2020): 3989–95. http://dx.doi.org/10.1073/pnas.1906507117.
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Natural gas is a key energy resource, and understanding how it forms is important for predicting where it forms in economically important volumes. However, the origin of dry thermogenic natural gas is one of the most controversial topics in petroleum geochemistry, with several differing hypotheses proposed, including kinetic processes (such as thermal cleavage, phase partitioning during migration, and demethylation of aromatic rings) and equilibrium processes (such as transition metal catalysis). The dominant paradigm is that it is a product of kinetically controlled cracking of long-chain hydrocarbons. Here we show that C2+n-alkane gases (ethane, propane, butane, and pentane) are initially produced by irreversible cracking chemistry, but, as thermal maturity increases, the isotopic distribution of these species approaches thermodynamic equilibrium, either at the conditions of gas formation or during reservoir storage, becoming indistinguishable from equilibrium in the most thermally mature gases. We also find that the pair of CO2 and C1 (methane) exhibit a separate pattern of mutual isotopic equilibrium (generally at reservoir conditions), suggesting that they form a second, quasi-equilibrated population, separate from the C2 to C5 compounds. This conclusion implies that new approaches should be taken to predicting the compositions of natural gases as functions of time, temperature, and source substrate. Additionally, an isotopically equilibrated state can serve as a reference frame for recognizing many secondary processes that may modify natural gases after their formation, such as biodegradation.
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Huang, Shu Jun, Hui Zhang, Cui Juan Shang, and Shu Long Jing. "Key Technologies of Rebuilding Underground Natural Gas Storages from Carbonate Buried Hill Gas Reservoirs." Advanced Materials Research 347-353 (October 2011): 1561–67. http://dx.doi.org/10.4028/www.scientific.net/amr.347-353.1561.
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In this paper, according to research difficulties of rebuilding underground natural gas storages from carbonate buried hill gas reservoirs, we select a variety of relevant technologies and methods to study. Considering the reservoir geologic features geology, the impact of water intrusion, the difference of reserve calculations and many other factors, we carry out the research and determine the key parameters of rebuilding underground natural gas storages, and finally get a reasonable understanding of the study. Upon completion of large-scale gas storage for research results, further to form the distinctive key technologies of rebuilding underground natural gas storages from carbonate buried hill gas reservoirs. The research results will provide the appropriate technical reference for similar future rebuilding underground gas storages and also provide the technical assurance for a safe and stable gas supply to Beijing, Tianjin and Hebei region.
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Xu, J. Q., G. Weir, L. Paterson, I. Black, and S. Sharma. "A CASE STUDY OF A CARBON DIOXIDE WELL TEST." APPEA Journal 47, no. 1 (2007): 239. http://dx.doi.org/10.1071/aj06015.
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This paper reports on the planning, procedure, results and analysis of a carbon dioxide (CO2) well test performed on Buttress–1, a well located in the Otway Basin, Victoria, Australia. A large-scale pilot study of CO2 sequestration is planned by the Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) in this area, which will involve, inter alia, taking CO2 from the Buttress reservoir and injecting it into a nearby depleted gas field. Understanding the production characteristics of this well is important to the success of this pilot, which forms part of a more extensive study to establish viable means to mitigate CO2 emissions to the atmosphere. This general backdrop forms the motivation for this study.Testing comprised of a standard suite of draw-downs and build-ups to determine reservoir/well characteristics, such as the well deliverability, the non-Darcy skin coefficient and the average reservoir permeability and volume.Compared to the wealth of experience developed over many years in testing oil and gas wells, the collective experience in CO2 well testing is extremely limited. The distinguishing features between this test and those of a typical natural gas well test need to be emphasised. Although, in general, flow testing a CO2 well should be similar to testing a natural gas well, differences in the thermodynamic properties of CO2 affect the analysis of the well test considerably. In particular, the non-Darcy skin effect is more pronounced and the wellbore and surface flow can involve dramatic phase changes, such as the formation of ice. Also, since CO2 is more compressible than a typical natural gas, the accurate measurement of the flow rate becomes more challenging. It is also apparent that the use of pseudo pressure, as opposed to simpler methods of dealing with the pressure dependency of key properties, is essential to the successful analysis of the pressure response to the CO2 production.
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Baranov, A. Yu, K. A. Valentinova, and L. V. Ivanov. "Modeling of liquefied natural gas evaporation in mobile reservoirs." Scientific and Technical Journal of Information Technologies, Mechanics and Optics 20, no. 4 (August 1, 2020): 595–602. http://dx.doi.org/10.17586/2226-1494-2020-20-4-595-602.
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Islam, Akand, and Tad Patzek. "Slip in natural gas flow through nanoporous shale reservoirs." Journal of Unconventional Oil and Gas Resources 7 (September 2014): 49–54. http://dx.doi.org/10.1016/j.juogr.2014.05.001.
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Aghakhanloo, Mahdi Naji, Mohsen Akef Ghalehni, and Ali Naji Aghakhanloo. "Simulation depleted natural gas reservoirs for compressed air storage." International Journal of Engineering and Technology 11, no. 4 (August 31, 2019): 869–77. http://dx.doi.org/10.21817/ijet/2019/v11i4/191104068.
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Rahman, Mohammad, and Sheik Rahman. "Induced and natural fracture interaction in tight-gas reservoirs." APPEA Journal 52, no. 1 (2012): 611. http://dx.doi.org/10.1071/aj11050.
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This paper investigates the interaction of an induced hydraulic fracture in the presence of a natural fracture and the subsequent propagation of this induced fracture. The developed, fully coupled finite element model integrates a wellbore, an induced hydraulic fracture, a natural fracture, and a reservoir that simulates interaction between the induced and natural fracture. The results of this study have shown that natural fractures can have a profound effect on induced fracture propagation. In most cases, the induced fracture crosses the natural fracture at high angles of approach and high differential stress. At low angles of approach and low differential stress, the induced fracture is more likely to be arrested and/or break out from the far-end side of the natural fracture. It has also been observed that the propagation of the induced fracture is stopped by a large natural fracture at a high angle of approach, when the injection rate remains low. At a low angle of approach, the induced fracture deviates and propagates along the natural fracture. Crossing of the natural fracture and/or arrest by the natural fracture is controlled by the shear strength of the natural fracture, natural fracture orientation, and the in situ stress state of the reservoir. In tight-gas reservoir development, the optimum well spacing and induced hydraulic fracture length are correlated. Therefore, fracturing design should be performed during the initial reservoir development planning phase along with the well spacing design to obtain an optimal depletion strategy. This model has a potential application in the design and optimisation of fracturing design in unconventional reservoirs including tight-gas reservoirs and enhanced geothermal systems.
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Li, Fengguang, Qing Yuan, Tianduo Li, Zhi Li, Changyu Sun, and Guangjin Chen. "A review: Enhanced recovery of natural gas hydrate reservoirs." Chinese Journal of Chemical Engineering 27, no. 9 (September 2019): 2062–73. http://dx.doi.org/10.1016/j.cjche.2018.11.007.
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Ghassemzadeh, Shahdad, Maria Gonzalez Perdomo, Manouchehr Haghighi, and Ehsan Abbasnejad. "A data-driven reservoir simulation for natural gas reservoirs." Neural Computing and Applications 33, no. 18 (March 16, 2021): 11777–98. http://dx.doi.org/10.1007/s00521-021-05886-y.
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Mohd Ismail, Mohd Dali, and Mofazzal Hossain. "The application of downhole gas compression to improve productivity for depleted natural gas reservoirs." APPEA Journal 53, no. 1 (2013): 369. http://dx.doi.org/10.1071/aj12032.
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Selection of an optimal artificial lift technology to prolong a depleted gas reservoir has always been a challenge in the oil and gas industry. To be able to have a solution that has low intervention costs and a long operating life is the key. Downhole gas compression (DGC) is the new form of artificial lift technology specifically designed, for gas wells, to increase productivity and maximise the recovery factor of the reservoir. DGC would provide a 20–40% production gain anytime during the production life-cycle of the well. Numerous challenges, however, associated with the design, development and implementation of this new technology are not well understood or documented. Thus, this study has been focused on understanding the key concepts of DGC technology and investigates its potential application for increasing the well productivity of gas wells through sensitivity studies. Emphases are given on the development of a mathematical model that can be used to investigate the effect of reservoir and well operating conditions with the production gain of DGC. This peer-reviewed paper presents the results of some case studies, identifying the key factors associated with the operating condition, well completion, and reservoir properties considered for the successful deployment of such an alternate form of artificial lift method for a gas well based on sensitivity analysis using a developed mathematical model. The sensitivity results confirm a significant gain of well productivity using DGC for certain reservoir and operating conditions.
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Sidrouhou, H. M., M. Korichi, and S. Dada. "Evaluation of Correlations of Compressibility Factor (z) of Natural Gas for Algerian Gas Reservoirs." Energy Procedia 157 (January 2019): 655–69. http://dx.doi.org/10.1016/j.egypro.2018.11.231.
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Vasil’ev, V. I., V. V. Popov, and G. G. Tsypkin. "Numerical investigation of the decomposition of gas hydrates coexisting with gas in natural reservoirs." Fluid Dynamics 41, no. 4 (July 2006): 599–605. http://dx.doi.org/10.1007/s10697-006-0078-z.
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Sun, Hai, Jun Yao, Sun-hua Gao, Dong-yan Fan, Chen-chen Wang, and Zhi-xue Sun. "Numerical study of CO2 enhanced natural gas recovery and sequestration in shale gas reservoirs." International Journal of Greenhouse Gas Control 19 (November 2013): 406–19. http://dx.doi.org/10.1016/j.ijggc.2013.09.011.
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Kondrat, R. M., O. R. Kondrat, and L. I. Khaidarova. "EXTRACTION OF THE RESIDUAL GAS DEPLETED GAS RESERVOIRS NITROGEN INJECTION." Prospecting and Development of Oil and Gas Fields, no. 2(71) (June 25, 2019): 20–29. http://dx.doi.org/10.31471/1993-9973-2019-2(71)-20-29.
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The relevance and feasibility of extracting residual gas from depleted gas deposits is shown. The possible directions of the extraction of residual gas from depleted gas deposits by its displacement from a porous medium of non-hydrocarbon gases are characterized. The use of nitrogen to displace natural gas from a porous medium has been substantiated. Using the GEM compositional modeling module, which is included in the licensed computer program CMG (Computer Modeling Group), studies were made of the effect of the pressure of the start of injection of nitrogen into the reservoir and the duration of its injection period on the gas recovery coefficient for residual gau. The study was conducted for deposits of square and round shape. The research results are presented in the form of graphical dependencies of the current reservoir pressure, nitrogen content in borehole products and gas recovery coefficient for residual gas from the pressure of the start of injection of nitrogen into the reservoir and the duration of the period of its injection. Using the results of the research, the optimal values of the parameters of the process of injecting nitrogen into the exhausted gas deposits of square and round forms and the corresponding values of the gas recovery coefficient were established. For the considered deposits of square and rounded forms, they are 0.29 Рin and 14.8 months, 0.31 Рin and 12.9 months, respectively. At the time of reaching the volumetric nitrogen content in the producing gas of 5 %, the gas recovery coefficient for residual gas for a square-shaped deposit is 83.91 %, for a round-shaped deposit – 77.49 %. The physical nature of the process of displacing residual gas with nitrogen from depleted gas deposits of square and round forms is characterized.
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Uliasz-Misiak, Barbara, and Katarzyna Chruszcz-Lipska. "Hydrogeochemical Aspects Associated with the Mixing of Formation Waters Injected Into the Hydrocarbon Reservoir." Gospodarka Surowcami Mineralnymi 33, no. 2 (June 27, 2017): 69–80. http://dx.doi.org/10.1515/gospo-2017-0017.
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Abstract Formation waters extracted with crude oil and natural gas, due to their amount and chemical composition can be a problem for petroleum companies operating hydrocarbon deposits. On average, the world generates 2 to 3 times more water than oil. On average, the world generates 2 to 3 times more water than crude oil. T he amount of extracted water increases with the time of exploitation of the deposit, in the case of deposits at the final stage of depletion, the amount of extracted water is 5 to 8 times bigger than petroleum. Formation waters from hydrocarbons deposits are usually the highly mineralized brines. Large quantities of highly mineralized waters extracted with crude oil and gas are disposed of in various ways or neutralized. T he most common way of disposing of these waters is by injecting them into rock mass. As a result of injection of reservoir waters into hydrocarbon deposits, the waters interact with the storage formations. In these formations, there may be numerous reactions of mineral water with the rock environment. T he injection of reservoir waters will also cause mixing of waters that can disturb the state of thermodynamic equilibrium and will alter the chemistry of these waters. It was analyzed by the geochemical modeling of the interaction of the reservoir waters of Przemyśl natural gas field. Using the PHREEQC program, the chemical reactions related to the mixing of reservoir waters of different chemical types have been studied. It has been found that is possible to precipitation appropriated minerals as a result of mixing water with different chemical composition.
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Xu, Chun-Gang, and Xiao-Sen Li. "Research progress on methane production from natural gas hydrates." RSC Advances 5, no. 67 (2015): 54672–99. http://dx.doi.org/10.1039/c4ra10248g.
Full textAbstract:
A review of the research on methane production from gas hydrates, including the research on the characteristics of gas hydrate reservoirs, production methods, numerical simulations and field production tests.
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Xue, Xiu Li, Yi Luo, and Pei Rong Zhao. "Ultimate Potential Nature Gas Resource Prediction and Exploration Direction in Sichuan Basin." Advanced Materials Research 998-999 (July 2014): 1498–503. http://dx.doi.org/10.4028/www.scientific.net/amr.998-999.1498.
Full textAbstract:
The ultimate natural gas resources of Sichuan Basin were predicted by the application of hydrocarbon reservoir scale sequence method. The results revealed that a total of 236 gas reservoirs exist in Sichuan Basin, with total expected natural gas resources of 57718×108m3.110 gas reservoirs are undiscovered, with geological reserves of 4.04×1012m3, accounting for70.0% of the total natural gas resources, among which, 17 undiscovered gas reservoirs have resources of more than 1000×108m3, 13 undiscovered natural gas reservoirs have resources of 500-1000×108m3 and 15 undiscovered gas reservoirs have resources of 100-500×108m3. The undiscovered natural gas resources mainly lie in the following key exploration fields: Permian-Triassic reef flat reservoir of Huankaijiang-Liangping continental shelf and deep to ultra-deep layers of continental Xujiahe Formation in West Sichuan, medium to shallow layers of Northeast Sichuan and Central Sichuan focused on Xujiahe Formation, piedmont zone of Longmen Mountain and Micang-Daba Mountain, oolitic flat of Jialingjiang Formation of East Sichuan, South Sichuan and North Sichuan as well as five large sets of unconformity surfaces, namely top surface of Sinian Dengying Formation, top surface of Middle-Upper Ordovician, top surface of Middle Carboniferous, top surface of Permian Yangxin Series and top surface of Leikoupo Formation.
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Zhou, Hang, Bingbing Chen, Shenglong Wang, and Mingjun Yang. "CO2/N2 mixture sequestration in depleted natural gas hydrate reservoirs." Journal of Petroleum Science and Engineering 175 (April 2019): 72–82. http://dx.doi.org/10.1016/j.petrol.2018.12.034.
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