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In this Tip of the Month (TOTM), we will study the effect of relative density (Specific Gravity, SG) on the saturated water content of sweet natural gases. The results of this study include the water content of sweet natural gases as a function of relative density in the range of 0.60 to 0.80. Four temperatures of 4.4, 23.9, 37.8 and 149 °C (40, 75, 100, and 300 °F) were considered. For each temperature, the saturated water content was calculated for pressures of 1724, 3448, 6897, and 13 793 kPaa (250, 400, 100 and 2000 psia). [Keep reading]

In this article, we will demonstrate how to determine the efficiency of a compressor from measured flow rate, composition, suction and discharge temperatures and pressures. A rigorous calculation based on an equation of state and a shortcut method are considered and the results are compared. From a calculation viewpoint alone, the compressor power calculation is particularly sensitive to the specification of mass flow rate, suction temperature and pressure, and discharge temperature and pressure. A compressor is going to operate under varying values of the variables affecting its performance. Thus the most difficult part of a compressor calculation is specification of a reasonable range for each variable and not the calculation itself. [Keep reading]

For transportation of crude oil, the pumping power requirement varies as the crude oil viscosity changes. Increasing °API or line average temperature reduces the crude oil viscosity. The reduction of viscosity results in higher Reynolds number, lower friction factor and in effect, lower pumping power requirements. To reduce pressure drop and increase pipeline capacity, oil industry has utilized drag reducing agents. Drag-reducing agents, or drag-reducing polymers, are additives in pipelines that reduce turbulence in a pipe. Usually used in petroleum pipelines, they increase the pipeline capacity by reducing turbulence and therefore allowing the oil to flow more efficiently. In addition to drag reducing agents, another group of chemicals called “Incorporative Additives”, which reduces crude oil viscosity, may be used. In this Tip of the Month, we will demonstrate the effect of an incorporative additive on crude oil viscosity and consequently on pressure drop for crude oil pipeline transportation. [Keep reading]

Molecular sieves are used upstream of turboexpander units and LNG facilities to dehydrate natural gas to <0.1 ppmv. In the natural gas industry, the molecular sieves employ heat to drive off the adsorbed water. The cyclical heating/cooling of the adsorbent results in a capacity decline due to a gradual loss of crystalline structure and/or pore closure. A more troublesome cause of capacity decline is contamination of the molecular sieves due to liquid carryover from the upstream separation equipment. Because of the capacity decline curves flatten out, available standby time may be able to extend the life of a molecular sieve unit when your unit is operating on fixed cycle times. Other operating options include: running each cycle to water breakthrough; and, reducing the cycle times in discreet steps throughout the life of the adsorbent. To illustrate the benefits of standby time, a case study was evaluated and the results are presented. [Keep reading]

In April's "Tip of the Month," we will present a set of correlations and simplified charts for estimating sour gas water content directly without having to look up the water content of sweet gas. These correlations are based on the Wichert and Wichert chart (Figure 20-9 of the GPSA data book) and Wagner and Pruss water vapor equation and Bukacek correlation for estimating sweet gas water content. The proposed correlations are valid for pressures up to 24 MPa (3500 psia), temperatures up to 175°C (350°F) and H2S equivalent concentrations of up to 50 mole %. The accuracy of the proposed correlations was compared against limited experimental data and a rigorous method using an equation of state. [Keep reading]

In this Tip of the Month (TOTM) we will discuss how to determine CO2 solubility and flashing issues in water at pressures and temperatures commonly associated with gathering systems and production facilities. This is mainly important for CO2 Enhanced Oil Recovery (EOR) floods as the CO2 concentration is high and the initial separation is at higher pressures than is common in non-CO2 EOR oilfields. These two conditions result in significant dissolving of CO2 into the produced water with resultant flash gas from downstream Free Water Knockouts (FWKO), treaters, and tanks. In mature CO2 EOR floods with Water-Alternating-Gas (WAG) injection schemes, it is likely that most of the flash gas in the downstream separations will be from the produced water. While this TOTM is significant mainly for CO2 EOR floods, the following analysis is general in nature; it would apply to other situations involving CO2 solubility in water issues. This analysis assumes that there is no H2S. H2S would have somewhat higher solubility than CO2 which would force more gas to flash from the FWKO and tanks. Higher H2S than about 5% would begin to appreciably increase the solubility of H2S into water. [Keep reading]