June 2013 • Oil and Gas Facilities 65 Summary The significance of setting optimal surface separation pressures cannot be overemphasized in surface-separation design for the purpose of maximizing the surface liquid production from the wellstream feed. Usually, classical pressure-volume-temperature (PVT) analysis of reservoir fluids provides one or several sepa- rator tests through which the optimum separator pressures are es- timated. In case separator tests are not available, or the limited numbers of separator tests are not adequate to determine the op- timum separator pressures, empirical correlations are applied to estimate the optimum separator pressures. The empirical correla- tions, however, have several disadvantages that limit their prac- tical applications. In this study, we approached the problem with a rigorous method with a theoretical basis. According to the gas/liquid equilibrium calculation, the optimum separator pressures were determined. Comparisons of our results with experimental data indicated that the proposed method can simulate the separator tests very well. Because the method has a theoretical basis and does not require existing two-stage or multiple-stage separator-test data as in the ap- plication of empirical correlations, it potentially has wide appli- cations in practice for a variety of conditions and yields a more optimal separation scheme than the empirical correlations. Further- more, the method is independent of reservoir fluid. In the event that separator tests are available from fluid analysis, our method can be used as a quality-control tool. Because the setting for optimal sepa- ration pressures vary as the composition of the wellstream changes during the field life, our method provides a quick and low-com- putational-cost approach to estimate optimum separator pressures corresponding to different compositions. Introduction Oil and gas production usually requires surface separation before they are transported to market. The pressure vessel used for sepa- rating well fluids produced from oil and gas wells into vapor and liquid components is called a separator. The vessel is engineered to separate production fluids into their constituent components of oil, gas, and water. These separating vessels are normally used on a producing lease or platform near the wellhead, manifold, or tank battery to separate the wellstream into gas, which goes to a gas pipeline; oil, which flows to a stock tank; and water, which is discharged to a water treatment facility. Separators work on the principle that the three streams (vapor-phase, liquid-oil, and liquid- water) have different densities, which allow them to stratify when moving slowly with gas on top, water on the bottom, and oil in the middle. A simplified diagram of such a vessel is illustrated in Fig. 1. Any solids such as sands will also settle in the bottom of the separator. There are several types of separators. In this paper, we discuss oil and gas separators. The surface separation system is a combination of separator/ separators and the stock tank. Different numbers of stages are ap- plied for different reservoir fluids. For the same fluid stream, more liquid yield is usually preferred because of its higher commer- cial value. Theoretically, the more stages of consecutive separa- tion exist, the higher the liquid production. However, in practice, the real number of separations is often limited by available space and operational cost. The simplest system is two-stage separation consisting of one separator and one stock tank. It is most appli- cable for low-API-gravity oils, low gas/oil ratios (GORs), and low flowing pressures. More complicated systems contain several sep- arators and stock tanks operated in series at successively lower pressures to maximize the liquid yield. The three-stage separation is used for intermediate gravity oils, intermediate to high GOR, and intermediate wellhead flowing pressures. The four-stage sepa- ration is designed for high-API-gravity oils, high GOR, and high flowing pressures. Four-stage separation is also used where high- pressure gas is needed for market or for pressure maintenance. The pressure of the separator is controlled with a backpressure valve through which the separated gas flows to the gas pipeline. The temperatures of the separator and the the stock tank are deter- mined by the temperature of the feed and ambience. Vaporization and expansion also affect the vessel temperature. Separator tem- perature can be adjusted by cooling and heating. The fact that the percentage of liquid recovery from surface separation is controlled by separator pressures and temperatures and stock-tank pressure and temperature for given wellstream composition is well known. There are optimum operating conditions for a certain system to separate a specific wellstream. During the production, there is a small room for the temperature adjustment. The pressure window of the primary separator is also narrow because it should be lower than the flowing tubing pressure (FTP) but higher than sale gas pipeline pressures because of the fact that if primary separator pressure is lower than gas pipeline pressure, recompression will be required, thus leading to high operating costs. Therefore, the opti- New Method To Estimate Surface- Separator Optimum Operating Pressures Kegang Ling, University of North Dakota; Xingru Wu, University of Oklahoma; Boyun Guo, University of Louisiana at Lafayette; and Jun He, University of North Dakota Copyright © 2013 Society of Petroleum Engineers Original SPE manuscript received for review 14 June 2012. Revised manuscript received for review 25 October 2012. Paper (SPE 163111) peer approved 13 November 2012. Fig. 1—Diagram of three-phase separator in the oil and gas sep- aration process. Vapor outlet Oil outlet Water outlet Feed header Vortex