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Two simple empirical correlations and a corresponding states method reported in the literature are used to estimate pure liquids surface tensions for the paraffins methane through n-octane. The two correlations express the surface tension as a function of the reduced temperature and molecular weight with only two (first correlation) and four (second correlation) fitted parameters. These correlations and the smoothed experimental data were used to generate three figures for methane through n-octane and a few heavy ends with known molecular weights. The fitted parameters for these figures will be presented. To evaluate the accuracy of the two correlations, the corresponding states method by Zuo and Stenby was used to estimate the liquid n-heptane surface tension at several temperatures. The estimated surface tension values were compared with the results by the two correlations against the experimental values. The summary of error analysis indicates that the accuracy of the generated figures and the two correlations are good and can be used for facilities calculations. Because of the simplicities and ease of calculations, the two correlations are suitable for hand calculations. While the calculations by Zuo and Stenby method can be done by hand, it is more convenient with spreadsheets. In a follow-up tip, the methods for estimation of surface tension for the paraffin liquid mixtures will be presented.

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In this Part 1 presentation of the initial Gas – Lift series, and effort has been made to provide for initial orientation regarding the important Gas – Lift history, initial background, initial production efforts, Gas – Lift components, and design criteria. Oil and Gas production has been an integral part of the World’s energy based economy for over 160 years. Improvements in new GLV designs were implemented after the 1940’s. In all GL applications, however, the pressure and volume of the injection gas was difficult to control due to the limited numerical models available to predict the Valves’ “CHOKE PERFORMANCE”. Injection Gas is injected down the tubing casing annulus through a series of “kick – off” (well flow initiation) Mandrels containing the applicable GLV, or the standing GLV at the bottom of the tubing string. The Mandrel is a single section of the production tubing string that allows insertion of the selected GLV. The solution Gas Oil Ratio, Rs, (GOR related in SCF/STB) is the gas that the reservoir oil has in solution in an oil reservoir at a specific pressure and temperature. This gas is liberated as the formation fluid is transported to the surface. The amount of flowing free gas will depend on the oil rate. The Oil Formation Volume Factor, Bo (Bbl/STB), also plays an important role in the solution gas being liberated by flowing pressures and temperatures.

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This Tip of the Month will discuss energy issues in the U.S, and highlight why there must be an “all of the above” approach to electricity generation technologies to ensure availability and reliability. The type of technology selected should be based upon what the local resources and environment can provide as there is no silver bullet, or one size fits all solution. Energy density of the various electricity generation technologies will be covered, and some examples of current performance will be examined.

Acid Gas Removal: Preventing Liquid Carry Over to and Condensation in the Amine Contactor

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Hydrogen sulfide and carbon dioxide are the principal objectionable acid gas components often present in natural gas, synthetic gas, and various refinery gas streams. These acid gas components must be removed for corrosion prevention in gas pipelines, process equipment, and for health and safety reasons. Reference [1] provides current acceptable concentration levels for these acid gases in various gas streams. Hydrogen sulfide removal often requires the production of sulfur in the sulfur recovery units to meet emission limits. Sulfur is a product used to produce sulfuric acid and fertilizers. Carbon dioxide removal is used for enhanced oil recovery and is required for carbon capture and sequestering (CCS) operations.

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In some cases, a choke/line heater is required at the wellsite to deal with the large JT expansion cooling effect experienced by choked high-pressure wells, especially during start-up. This is a somewhat different application than prevention of hydrates in the GGS but there are some common aspects to the equipment utilized. First, the hydrate temperature of the flowing wellstream is estimated. From Figure 1, for 0.65 SG gas and assuming any free water present is condensed/fresh water, the estimated hydrate temp at an assumed average GGS pressure of 1,100 psig is ~ 65 F.


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