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MEASUREMENT OF BODY FLUID VOLUMES#physiologyMeasuring fluid composition -
Chemical Geology, , 35— Stalder, R. Geochimica et Cosmochimica Acta, 62 10 , — Tatsumi, Y. Journal of Geophysical Research, 94, — Tropper, P. American Mineralogist, 90, — Chemical Geology, , 54— Tsay, A. Walther, J. Geochimica et Cosmochimica Acta, 61, — Weiss, Y. Wilke, M.
Earth and Planetary Science Letters, , 15— Zarei, A. ACS Earth and Space Chemistry, 2, — Your purchase has been completed. Your documents are now available to view.
Licensed Unlicensed Requires Authentication Published by De Gruyter December 31, From the journal American Mineralogist.
Cite this Share this. Showing a limited preview of this publication:. Abstract A variety of experimental techniques have been proposed to measure the composition of aqueous fluids in high-pressure experiments.
Acknowledgments and Funding We thank M. Received: Accepted: Published Online: Published in Print: Cite this article. MLA APA Harvard Chicago Vancouver. Rustioni, Greta, Audétat, Andreas and Keppler, Hans. A systematic assessment of the diamond trap method for measuring fluid compositions in high-pressure experiments.
American Mineralogist , 1 , and Keppler, H. American Mineralogist, Vol. Rustioni G, Audétat A, Keppler H. American Mineralogist. Copied to clipboard. Copy to clipboard. Download: BibTeX EndNote RIS. Share this article. Having a good estimate for the in-situ fluid composition is crucial for modeling and forecasting surface gas and oil rate GOR behavior, resulting in enhanced reserves estimation.
Moreover, if we have in-situ compositions for all wells, it is possible to generate a compositional map which can be used for optimizing the development of a field or basin. The main reason why this is not common practice today is because of the misconception that in-situ compositions can only be found by sampling and PVT laboratory measurement.
This is not necessarily the case. A reservoir representative fluid sample is any uncontaminated fluid sample that originates from the reservoir. This definition spans anything from expensive down-hole sampling to inexpensive separator samples.
An in-situ representative fluid sample is a sample representative of the original fluid in place. It is worth noting that any in-situ representative sample will, by definition, also be reservoir representative, but not all reservoir representative samples are in-situ representative.
In the paper by Fevang and Whitson, some experimental and some computational methods were proposed in which inexpensive, reservoir representative, fluid samples are used to recombine and reconstruct a fluid composition that is in-situ representative. The proposed methods are called equilibrium contact mixing ECM and have been studied and used for many reservoirs around the world for the past 25 years.
In summary we can 1 use experimental methods to reconstruct the in-situ fluid, 2 rely on computational methods or 3 use a hybrid ECM method. In certain embodiments, separate gas chromatographs can be utilized for the analysis, and in certain embodiments the separate gas chromatographs can be separately configured for the analysis of gas or liquid residue fractions.
In first step , the liquid masses of each component in the hydrocarbon sample, up to and including the C29 component, are calculated. A gas chromatograph can be used to determine the compositional make-up of the hydrocarbon sample up to the C29 component.
For clearly defined components, such as CI to C5, the liquid masses are calculated by multiplying the molecular weight of the component by the measured mole fraction of the component. For fractional cuts, such as for example, C6, CI 2, up to C29, the molecular weight is selected from published values such as, Handbook of Natural Gas Engineering, by Donald Katz.
In step , the calculated molecular weight from step is compared against the measured molecular weight, to determine if the difference between the calculated molecular weight and measured molecular weight are within a pre-determined range to be considered sufficiently accurate.
The procedure is repeated until the difference between the calculated molecular weight and the measured molecular weight for the fluid is determined to be sufficiently accurate. In first step , the liquid volumes of the components up to the C29 component, including non hydrocarbon components like nitrogen gas, are calculated.
The fluid density for the total liquid sample is calculated by dividing the total liquid weight of the sample, as determined in step described above, by the total liquid volume determined in step In step , the calculated fluid density determined in step is compared with the measured fluid density to determine if the calculated density and the measured density are within a pre-determined range such that they are to be considered sufficiently accurate to proceed.
Alternatively, if the difference between the calculated density and the measured density are not sufficiently accurate, i. The procedure is repeated until the difference between the calculated density and the measured density for the fluid is determined to be sufficiently accurate. The hydrocarbon sample is heated to a temperature of at least about °F, preferably to a temperature of about °F, to produce the gas fraction and a liquid residue fraction, wherein the gas fraction includes carbon compounds up to about C6 , dissolved gasses such as nitrogen, hydrogen sulfide and carbon dioxide, and trace amounts of C7 and C8 compounds.
The number of moles of the liquid sample can be determined by dividing the measured mass of the liquid fraction by the measured molecular weight of the liquid fraction. Average molecular weight can be determined by freezing point depression. The number of moles of the gas sample can be determined, for example, by dividing the measured volume of gas fraction at standard conditions 60°F with the known volume of one mole of gas at standard conditions 23, cm 3.
The total number of moles was determined, for example, by adding the number of moles of the liquid residue fraction and the number of moles of the gas fraction. The sum of the individual moles of each of the gas and liquid residue fractions can then be calculated. The wellstream mole composition can then be determined, for example, by dividing the mole fraction of each component in the liquid residue fraction and the gas fraction by the total number of moles for both the liquid residue and the gas fractions.
A mole percentage can then be determined from the calculation. The areas for each individual peak correspond to the concentration of each individual compound present within an injected sample.
Peak areas are typically automatically calculated by the gas chromatograph, and can be a main input into an associated computer program that can be utilized for determining the overall wellstream composition of a hydrocarbon sample.
For example, the thermal conductivity detector responses can be measured for various compounds, including nitrogen, carbon dioxide, and alkanes having between 1 and 9 carbon atoms, based upon the mass injected and the peak areas from the analysis of the standard samples.
For example, in certain embodiments of the present invention, a liquid mixture that includes a known concentration of hydrocarbons having between about 5 and 16 carbon atoms can be prepared by measuring between about 0. Density of the calibration sample can be calculated by comparing the empty mass of the flask, and the mass of the flask with the liquid samples placed therein.
In addition, providing accurate compositional data is essential to the tuning of equation of state fluid characterization models for input into reservoir and process simulations.
The technique presented in this paper has been successfully used to acquire an extended well-stream composition of oil and gas samples and it has several advantages over the traditional method of compositional analysis. In other embodiments, the methods according to the present invention include flashing the sample at atmospheric conditions by heating the hydrocarbon or wellstream oil sample up to about °F, rather than heating the vessel to temperatures greater than about °F, or even above about °F, as required by the prior art.
In addition to requiring additional energy and equipment, heating the sample being analyzed to the higher temperatures can result in partial cracking of the fluid sample, thereby providing an inaccurate determination of the composition of the sample.
The recovered gas and liquid fractions from the flashing of the hydrocarbon sample, according to the present invention, can be analyzed using gas chromatography, and the resulting compositional analysis can then be imported into a computer program designed for accurate quantification of the analysis.
The measured volumes of the various fractions and the measured molecular weight and density of the liquid residue fraction can then be utilized and applied to compute a well-stream composition for the fluid.
Thus, in certain embodiments of the present invention, the use of the present methods can result in the saving of significant time, and can increase and in certain instances, double the number of fluids analyses that can be performed each year.
The sampling end of the cylinder was connected to the receiving end of the still, which in turn was connected through the still outlet to the inlet of the topping cylinders.
When all connections were completed between the cylinders, the system was evacuated through the topping unit to the sample end of the cylinder. The sample end valve was then opened slightly, thereby ensuring that the sample pressure was maintained at a pressure that was above the bubble point pressure.
Between about 50 and mL of sample, depending on the nature of the fluid sample, were flash heated at room temperature conditions. For example, the fluid sample was heated to a temperature of about °F, and the evolved gas was collected and measured at the topping unit. Additionally, the collected gas sample was analyzed by gas chromatography and also measured to determine the volume of the collected gas sample.
In a similar fashion, liquid residue was cooled and collected for gas chromatographic analysis, and the density and molecular weight were also measured. Table 1 provides an exemplary calibration for a natural gas analyzer. The calibration results demonstrate good reproducibility with the composition of the standard up to the C9 hydrocarbon components, with particular accuracy being shown light compounds up to and including the C5 hydrocarbon components.
Table 2. Condensate GC Calibration with Liquid Mixture. Table 3 shows the calibration results. Table 3. Condensate Gas Chromatograph Calibration with Gas Oil Reference Mixture. Table 4. Oil GC Calibration with Gas Oil Reference Mixture.
Component Composition wt. Comparisons of the mole percent of the prepared sample and the measured values as determined by the gas chromatograph show good results. Table 5. Oil GC Calibration with Liquid Mixture. Samples were analyzed using the techniques described herein, wherein the liquid sample is heated to a temperature of about °F to produce a liquid and a gas fraction, and each fraction was subsequently analyzed by gas chromatography.
Results of the analyzed gas compositions and the liquid compositions were mathematically recombined using a computer program. A gas chromatogram that includes the total area of the gas and the liquid fractions was directly loaded into the computer program.
The weight of the liquid sample and the measured density of the stock tank oil were also entered into the program. In addition, the pressure and temperature during the flash heating were recorded by a manometer and a thermocouple, respectively, which were coupled to the topping unit. Finally, the total volume of gas measured at the topping unit at the flashed temperature and pressure was measured and entered into the computer program.
The well stream composition was calculated using methods according to an embodiment of the present invention. The compositional analysis of a well stream determined utilizing conventional methods are provided in Table 9. The molecular compositions were found to be similar, however there is noticeable variation in the amount of heptanes plus and the dodecanes plus fractions, most likely because of the increased temperature the fluids were subjected to in the conventional method.
Accurate determination and the availability of extended fluid composition of reservoir fluids is critical, not only to characterize and produce the reservoir, but also to design well completions and process systems. The table provides the results of the gas and liquid fractions, and shows the combined total well-stream composition.
Table 6B shows individual properties of the well-stream composition. Similar results are shown in Tables 7A and 7B for a volatile oil sample and in Tables 8A and 8B for a gas condensate sample. C3 Properties of Well-XXX. Black Oil. Table 7A. Composition of Well-XXXX.
Volatile Oil. Component MW Separator Gas Separator Oil Well-Stream. Properties of Well-XXXX.
Previous Index Next. Compartment composiiton are measured by determining the volume of distribution compositiion a tracer substance. Compisition known amount of Circuit training for overall fitness Measuring fluid composition is added to a compartment. Flud tracer concentration Peppermint oil uses that compartment compositiin measured after allowing sufficient time for uniform distribution throughout the compartment. The compartment volume is calculated as:. If the tracer is excreted in the urine, then the loss can be determined and corrections made in the calculation. If the tracer is metabolised, a series of measurements can be made and assuming exponential decline first order kineticsthe volume of distribution can be determined by extrapolation back to zero time.
Flow measurement is the quantification of bulk fluid movement. Flow can be measured using devices called flowmeters Peppermint oil uses various ways. The common coomposition of flowmeters with Organic beauty products applications Measuring fluid composition listed Measuring fluid composition. Flow fuid methods other than positive-displacement flowmeters rely on compositino produced by Meashring flowing stream as it overcomes a known constriction, to indirectly calculate flow. Flow may be measured by measuring the velocity of fluid over a known area. For very large flows, tracer methods may be used to deduce the flow rate from the change in concentration of a dye or radioisotope. Both gas and liquid flow can be measured in physical quantities of kind volumetric flow rate or mass flow rateswith respective SI units such as cubic meters per second or kilograms per second, respectively.
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