The Experts below are selected from a list of 27 Experts worldwide ranked by ideXlab platform
John J Carroll - One of the best experts on this subject based on the ideXlab platform.
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hand calculation methods
Natural Gas Hydrates (Third Edition)#R##N#A Guide for Engineers, 2014Co-Authors: John J CarrollAbstract:This chapter explores hand calculation methods useful for rapid estimation of the hydrate formation conditions. Unfortunately, the drawback to these methods is that they are not highly accurate. Moreover, in general, the less information required as input, the less accurate the results of the calculation. In spite of this, these methods remain quite popular. There are two commonly employed methods for rapidly estimating the conditions at which hydrates will form. Both are attributed to Katz and coworkers. The two methods are distinguished by the names “Gas Gravity” and “K-factor.” The Gas Gravity method involves only a single chart which is simple to use. For example, if one know the pressure, temperature, and Gas Gravity and wants to know if one is in a region where a hydrate will form; first, locate the pressure-temperature point on the chart. If this point is to the left and above the appropriate Gravity curve, one is in the hydrate-forming region. If one is to the right and below, one is in the region where a hydrate will not form. Remember that hydrate formation is favored by high pressure and low temperature. The second method that lends itself to hand calculations is the K-factor method. A third chart method proposed by Baillie and Wichert is a Gas Gravity approachthat is more useful for sour Gas mixtures.
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chapter three hand calculation methods
Natural Gas Hydrates (Second Edition)#R##N#A Guide for Engineerss, 2009Co-Authors: John J CarrollAbstract:Publisher Summary This chapter explores hand calculation methods useful for rapid estimation of the hydrate formation conditions. Unfortunately, the drawback to these methods is that they are not highly accurate. Moreover, in general, the less information required as input, the less accurate the results of the calculation. In spite of this, these methods remain quite popular. There are two commonly employed methods for rapidly estimating the conditions at which hydrates will form. Both are attributed to Katz and coworkers. The two methods are distinguished by the names “Gas Gravity” and “K-factor.” The Gas Gravity method involves only a single chart which is simple to use. For example, if one know the pressure, temperature, and Gas Gravity and wants to know if one is in a region where a hydrate will form; first, locate the pressure-temperature point on the chart. If this point is to the left and above the appropriate Gravity curve, one is in the hydrate-forming region. If one is to the right and below, one is in the region where a hydrate will not form. Remember that hydrate formation is favored by high pressure and low temperature. The second method that lends itself to hand calculations is the K-factor method. A third chart method proposed by Baillie and Wichert is a Gas Gravity approachthat is more useful for sour Gas mixtures.
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chapter 3 hand calculation methods
Natural Gas Hydrates#R##N#A Guide for Engineers, 2003Co-Authors: John J CarrollAbstract:Publisher Summary Hand calculation methods are useful for rapid estimation of hydrate formation conditions. Two methods are commonly employed for rapidly estimating the conditions at which hydrates will form. They are: the Gas Gravity method and the K-factor method. The Gas Gravity method is simple, involving only a single chart. The chart is simply a plot of pressure and temperature, with the specific Gravity of the Gas as a third parameter. The K-factor method is designed for calculations involving a Gas and a hydrate. The K-factor is defined as the distribution of the component between the hydrate and the Gas. The K-factor method, as given on the companion Website, is surprisingly accurate for predicting the hydrate locus of pure methane, ethane, carbon dioxide, and hydrogen sulfide. Baillie and Wichert developed another chart method for hydrate prediction. The basis for this chart is the Gas Gravity, but the chart is significantly more complex than the Katz Gravity method. Despite their relative simplicity, these methods are surprisingly accurate. The Baillie-Wichert method is better than the Gas Gravity method when applied to sweet Gas because of the inclusion of a correction factor for propane. The real advantage of this method is that it is applicable to sour Gas mixtures.
Martin J Blunt - One of the best experts on this subject based on the ideXlab platform.
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multi rate transfer dual porosity modeling of Gravity drainage imbibition
Annual Simulation Symposium, 2005Co-Authors: G Di Donato, Huiyun Lu, Zohreh Tavassoli, Martin J BluntAbstract:We develop a physically motivated approach to modeling displacement processes in fractured reservoirs. To find matrix/ fracture transfer functions in a dual-porosity model, we use analytical expressions for the average recovery as a function of time for Gas Gravity drainage and countercurrent imbibition. For capillary-controlled displacement, the recovery tends to its ultimate value with an approximately exponential decay (Barenblatt et al. 1990). When Gravity dominates, the approach to ultimate recovery is slower and varies as a power law with time (Hagoort 1980). We apply transfer functions based on these expressions for core-scale recovery in field-scale simulation. To account for heterogeneity in wettability, matrix permeability, and fracture geometry within a single gridblock, we propose a multirate model (Ponting 2004). We allow the matrix to be composed of a series of separate domains in communication with different fracture sets with different rate constants in the transfer function. We use this methodology to simulate recovery in a Chinese oil field to assess the efficiency of different injection processes. We use a streamline-based formulation that elegantly allows the transfer between fracture and matrix to be accommodated as source terms in the 1D transport equations along streamlines that capture the flow in the fractures (Di Donato et al. 2003; Di Donato and Blunt 2004; Huang et al. 2004). This approach contrasts with the current Darcy-like formulation for fracture/matrix transfer based on a shape factor (Gilman and Kazemi 1983) that may not give the correct average behavior (Di Donato et al. 2003; Di Donato and Blunt 2004; Huang et al. 2004). Furthermore, we show that recovery is exceptionally sensitive to parameters that describe the physics of the displacement process, highlighting the need to make careful core-scale measurements of recovery.
Dominique Richon - One of the best experts on this subject based on the ideXlab platform.
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determination of water content of natural Gases state of the art
2008Co-Authors: Amir H Mohammadi, Dominique RichonAbstract:Natural Gases normally contain significant quantities of water. During production, transportation and processing operations, undesired amounts of dissolved water may condense altering the physical state from vapor to condensate, Gas hydrate and / or ice. Condensate formation may lead to corrosion and / or two-phase flow problems. The formation of Gas hydrate/ice could result in pipelines blockage and shutdown. Accurate knowledge of phase behavior in water + natural Gas system, especially near and inside the Gas hydrate or ice formation regions, is therefore of interest to avoid these problems. Experimental data for water content of Gases at low temperatures, especially near and inside the Gas hydrate or ice formation regions, are rare and scarce. This is partly due to the fact that the water content is very low at these conditions and hence generally difficult to measure it. Furthermore, reaching equilibrium at low temperatures is a time consuming process. The aim of this communication is to present advances in predicting water content of natural Gases. After review of the existing methods reported in the literature for estimating water content of Gases, we introduce useful remarks to reduce experimental information required to determine water content of Gas in equilibrium with liquid water, Gas hydrate or ice. A semi-empirical method is then introduced for determining the water content of natural Gases in equilibrium with liquid water or ice. This method allows calculating the water content using liquid water / ice vapor pressure and molar volume of liquid water / ice as well as pressure and temperature of the system. A mathematical correction factor based on the McKetta - Wehe chart, which is a function of Gas Gravity and the system temperature, can be used to take into account the effect of heavy hydrocarbons on the water content of Gases in equilibrium with liquid water. In order to extend the capability of this method to sour Gases, a mathematical correction factor, which is a function of concentration of acid Gases in the system and the system temperature as well as the system pressure, can be used for taking into account the effect of acid Gases on the water content of Gases in equilibrium with liquid water. Another semi-empirical method for determining water content of methane-rich hydrocarbon Gas in equilibrium with Gas hydrates is then introduced. The methode estimates the water content of methane using the vapor presure of the empty hydrate lattice and the partial molar volume of water in the empty hydrate as well as pressure and the temperature of the system. In order to extend the capability of this tool for determining water content of methane-rich hydrocarbon Gas in equilibrium with Gas hydrates, a correction factor, which is a function of Gas Gravity and the pressure, can be used.
Susanne Poulsen - One of the best experts on this subject based on the ideXlab platform.
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rate effects on centrifuge drainage relative permeability
SPE Annual Technical Conference and Exhibition, 2000Co-Authors: Arne Skauge, Susanne PoulsenAbstract:Estimation of oil drainage relative permeability can be made from centrifuge measurements either by single-step or multi-step experiments. This paper compares relative permeability calculated from the two centrifuge methods to data from long core Gravity drainage Gas injection. Simulations of centrifuge single-step drainage experiments at varying rpm have been performed, with independent measured capillary pressure included. The relative permeability curves hereby estimated seem to be rpm (rotations per minute) dependent. The paper gives recommendation for a minimum or critical Bond number for which capillary pressure can be ignored in drainage relative permeability calculations. Simulation of long core Gas Gravity drainage experiments supports the results of the single-step centrifuge drainage at low rotational speed. The multi-step centrifuge experiments have the benefit of simultaneous calculation of both relative permeability and capillary pressure. However we find the multi-step technique to overestimate capillary pressure and underestimate oil relative permeability. These results come from comparing with direct capillary pressure measurements and relative permeability derived from long-core or single step centrifuge data corrected for capillary pressure.
G Di Donato - One of the best experts on this subject based on the ideXlab platform.
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multi rate transfer dual porosity modeling of Gravity drainage imbibition
Annual Simulation Symposium, 2005Co-Authors: G Di Donato, Huiyun Lu, Zohreh Tavassoli, Martin J BluntAbstract:We develop a physically motivated approach to modeling displacement processes in fractured reservoirs. To find matrix/ fracture transfer functions in a dual-porosity model, we use analytical expressions for the average recovery as a function of time for Gas Gravity drainage and countercurrent imbibition. For capillary-controlled displacement, the recovery tends to its ultimate value with an approximately exponential decay (Barenblatt et al. 1990). When Gravity dominates, the approach to ultimate recovery is slower and varies as a power law with time (Hagoort 1980). We apply transfer functions based on these expressions for core-scale recovery in field-scale simulation. To account for heterogeneity in wettability, matrix permeability, and fracture geometry within a single gridblock, we propose a multirate model (Ponting 2004). We allow the matrix to be composed of a series of separate domains in communication with different fracture sets with different rate constants in the transfer function. We use this methodology to simulate recovery in a Chinese oil field to assess the efficiency of different injection processes. We use a streamline-based formulation that elegantly allows the transfer between fracture and matrix to be accommodated as source terms in the 1D transport equations along streamlines that capture the flow in the fractures (Di Donato et al. 2003; Di Donato and Blunt 2004; Huang et al. 2004). This approach contrasts with the current Darcy-like formulation for fracture/matrix transfer based on a shape factor (Gilman and Kazemi 1983) that may not give the correct average behavior (Di Donato et al. 2003; Di Donato and Blunt 2004; Huang et al. 2004). Furthermore, we show that recovery is exceptionally sensitive to parameters that describe the physics of the displacement process, highlighting the need to make careful core-scale measurements of recovery.
