Flowline temperature

Flowline temperature is also an overpressure indicator. In overpressured zones the formation temperature increases. The flow line temperature gradient (increase in temperature per 100 ft) can increase by 2° to 10° over the normal gradient. However, other effects (salt domes, lithology changes) may also cause gradient changes. 

The oil and gas samples are taken from the appropriate flowlines of the same separator, whose pressure, temperature and flowrate must be carefully recorded to allow the recombination ratios to be calculated. In addition the pressure and temperature of the stock tank must be recorded to be able to later calculate the shrinkage of oil from the point at which it is sampled and the stock tank. The oil and gas samples are sent separately to the laboratory where they are recombined before PVT analysis is performed. A quality check on the sampling technique is that the bubble point of the recombined sample at the temperature of the separator from which the samples were taken should be equal to the separator pressure. 

Collect a 350-ml mud sample from the flowline and place the sample in the glass Jar. Allow the sample to cool to room temperature before the test is conducted. Mix at 70 V with the mixer for 1 hr. Pour the mud out, add 100 ml diesel oil, and shake well. (Do not stir with mixer.) Pour the oil out, add 50 ml xylene-isopropyl alcohol (1 1) mixture, and shake well. Empty jar, turn upside down, and allow to dry. Observe the film on the wall of the jar and report the evaluation as... 

Simulated pipe coalescence at temperatures above 40n C combined with demulsifier Injection is beneficial for the dehydration performance (Table ), giving residual water-in-oll after 30 minutes settling time of less than U. No pipe coalescence can be expected at 20° C. In an uninsulated flowline, the temperature (Fig. 4) will rapidly decrease to below 20° C, and the residence time in the hotter section of the flowllne will not be sufficient for effective coalescence. 

The temperature of crude flowing through an uninsulated flowline will be reduced to seabed temperature (circa 5°C) at a short distance from the wellhead (Fig. 4). The Troll crude which contains some 2.5 X wax may... 

The col was filled with a bottom hole crude sample and immersed in a thermostatted bath. After one hour at 46°C, the temperature of the bath was gradually decreased at 1.5°C/hr to 4°C and maintained at this temperature for two weeks. After the test period, flow was obtained by applying 0.04 bar (equivalent to 30 psi In field with 5" flowline), indicating that cold start-up would not be a problem ir the field. 

The objective of this test was to assess the wax deposition tendency of Troll crude in a cool subsea flowline. The equipment consists of a thermostatted stirred vessel from which crude oil is circulated by a gear pump through a thermostatically controlled stainless steel capillary. Tne temperature in the vessel was maintained at 6S°C and the capillary tube was held at a constant temperature below the cloud point. 

Flow In an uninsulated subsea flowline Is cooled from 55°C to a seabed temperature of 5°C (Fig. 4), some 1200 m from the wellhead. Beyond this point wax deposit will be minimal since there is no temperature differential. Within 60 meters of the wellhead, the stream temperature is 1n excess of 35°C and no accumulation of wax will occur any wax deposited during a shutdown would be redissolved when flowing. 

Full insulation of the flowline to achieve crude arrival temperatures in excess of 35°C is pronioitively expensive ano naro to realise. Potential wax deposition must therefore be countered by the provision of pigging/scrapina facilities and by injection of wax modifier at the wellhead. 

The subsea flowline and riser conditions can be expected to vary depending on flowline length and diameter, well PI, GDR, water cut, reservoir pressure etc. To Illustrate the possible variation, three cases representing high, optimum and solution GOR are given in Fig. 8. At start-up, temperatures will be circa 5°C, (sea bed temperature) for all cases. 

Figure 8 Flowline Operating Temperature and Pressure Ranges Related to Hydrate Formation Region.

ESTIMATED FLOWING TEMPERATURE PROFILE ALONG 5"ID SUBSEA OIL FLOWLINES... 

Consequently, gas evolution at the surface cannot be reliably measured for hydrate dissociation. However, it is possible to predict nonpressurized core hydrate dissociation during this trip (Davies and Sloan, 2006) as a function of the depth-temperature-time profile during the coring. The model for nonpressurized core dissociation is modified from CSMPlug (in the book s endpapers) for hydrate plug dissociation in flowlines. 

Figure 8.1 shows the pressure and temperature of fluids in a flowline at various points along the ocean floor, predicted by a multiphase flow prediction program. As a unit mass of fluid traverses the pipeline, the pressure drops normally due to friction losses associated with fluid flow. However, the temperature decrease is more interesting. 

Avoidance of the hydrate formation thermodynamic conditions of temperature, pressure, or inhibitor concentration, makes it impossible for plugs to form. The calculations of thermodynamic conditions can be made with acceptable accuracy. Using the methods presented in Chapters 4 and 5 along with the CD program CSMGem provided with this book, the temperature, pressure, and inhibitor concentrations can be calculated respectively, to within 2°F, 10% in pressure and 3% of inhibitor concentration. Since the discovery of hydrate flowline plugs in 1934, such thermodynamic methods have served to provide the major method of flow assurance. 

Prediction of the temperatures and pressures of hydrate formation for an infinite variety of mixtures of the above eight components. This enables specification of flowline insulation or heating, to prevent fluids from entering the hydrate formation region. 

An alternative stopped-flow attachment, designed for use with Jasco J-700 series spectropolarimeters, is the HI-TECH Scientific SHU-61CD with pneumatic drive. Its temperature range is 5-80 C, its pathlength is 2 mm, it has a 3.5 mm window size and a cell volume of 19 (i,l. The mixer is integral to the cell. 200 p,l is required per shot with 2 ml to prime the flowlines. Drive syringes may be altered to allow variable mixing. Hi-Tech do not offer a dedicated stopped-flow circular dichroism system. 

The gas condensate phase is composed of C3 and heavier alkanes and alkenes, present in the gas phase at reservoir conditions, that condense due to the temperature and pressure drop in the well string during production or in flowlines and production facilities. The gas condensate phase can occur in gas wells, flowlines, and in crude oil well gas processing facilities after separation of gas from the crude... 

Figure 2,40 also shows the temperature profiles for n = 3, The factor n in the cosine term dictates the number of cells in the x-direction.This is because the flowlines will turn whenever dpjdx is zero. Figure 2.44 provides the velocity contours for n = 3, showing that there are indeed three cells. Note the alternation in the velocity directions of the neighboring cells. 

Phase changes during the transportation of crude oil or natural gas results in two-phase oil/gas flows. When the hot fluid from the reservoir rises to the sea floor, the extreme temperature changes can cause liquefaction of the gas. Also, due to the long distances used in multiphase flowlines, pressure drop can cause flashing and a change of phase. 

The more troublesome ions are those that react to form precipitates when pressure, temperature, or composition changes occur. These are the well-known deposits that form in tuhing, flowlines, vessels, and produced water treating equipment. 

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