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Two-phase flow through wellhead chokes, including both critical and subcritical flow and the boundary between them, was studied. Data were gathered for air-water and air-kerosene flows through five choke diameters from 1/4 in. (6.35 mm) to 1/2 in. (12.7 mm), and results were compared to published correlations. A new theoretical model for predicting flow rates and the critical-subcritical flow boundary was tested against these data, as well as data from two published studies. The new model substantially improves the existing methods for predicting choke behavior in two-phase flow. Introduction Chokes are widely used in the petroleum industry to protect surface processing equipment from slugging, to protect surface processing equipment from slugging, to control flow rates from wells, to provide the necessary backpressure to a reservoir to avoid formation damage from excessive drawdown, to maintain stable pressure downstream from the choke and dampen large pressure fluctuations. Either critical or subcritical flow may exist. Since different methods apply for predicting choke behavior in these regimes, the prediction of the critical-subcritical flow boundary is also important. The majority of correlations available apply to critical flow only. Pressure drops through chokes can be substantial. For example, in critical flow the pressure downstream from the choke may be as low as pressure downstream from the choke may be as low as 50% or even 5% of the upstream pressure. Modern techniques, like Nodal* Analysis, of analyzing the entire production system require two-phase models of production system require two-phase models of comparable accuracy for each system component. Thus, to optimize the performance of the entire production system, an improved two-phase choke model is required. THEORY For the purpose of modeling, a wellhead choke can be treated as a restriction in a pipe. Two types of two-phase flow can exist in a choke: critical and subcritical flow. During critical flow, the flow rate through the choke reaches a maximum value with respect to the prevailing upstream conditions. The velocity of the fluids flowing through the restriction reaches the sonic or pressure wave propagation velocity for the two-phase fluid. This implies that the flow "choked" because downstream disturbances cannot propgate upstream. Therefore, decreasing the downstream propgate upstream. Therefore, decreasing the downstream pressure does not increase the flow rate. If the pressure does not increase the flow rate. If the downstream pressure is gradually increased, there Will be no change in either the flow rate or the upstream pressure until the critical-subcritical flow boundary pressure until the critical-subcritical flow boundary is reached. If the downstream pressure is increased slightly beyond the boundary conditions, both flow rate and upstream pressure are affected. The velocities of fluids passing through the choke drop below the sonic velocity of the upstream fluids. Here, the flow rate depends on the pressure differential and changes in the downstream pressure affect the upstream pressure. This behavior characterizes subcritical pressure. This behavior characterizes subcritical flow. Although it is often desirable to operate wells under critical flow conditions with uniform flow rate and downstream pressure, Fortunate' reports that a majority of wells in the field operate under subcritical conditions. However, most of the correlations available to petroleum industry are for critical flow. Existing Methods A complete model for two-phase flow through chokes should define the boundary between the critical and subcritical flow regimes and predict the functional relationships of flow rate through the choke and the pressure differential across the choke for a given set of fluid properties and flow conditions. Most existing methods model critical flow only and a few even attempt to define the criticalsubcritical flow boundary. These models are surveyed.

A comprehensive investigation was undertaken to study two-phase flow in a radial electric submersible pump (ESP) using diesel/C0 2 mixture data from an earlier study. CUrrently, no dynamic model is available for multistage pumps. A dynamic five-equation model was developed and verified. The model incorporates pump geometry, stage inlet pressure, inlet void fraction, fluid properties, and number of stages. The two-phase flow physics for the pump is found to be vastly different from that in pipe flow. Insights into a pump's surging tendency were obtained.

This is a continuation of the earlier work on the I-42B pump presented by Sachdeva1. The dynamic model developed earlier is extended to include axial geometries. Correlations are developed for CD/rb -- the only correlating factor required to complete the model. The performance of radial C-72 and axial K-70 pumps under gassy conditions is studied. Besides the dynamic model, a simple correlation (Model 2) for predicting the pressure rise per stage is also developed for the C-72, K-70 and I-42 pumps.

A tapered electric submersible pump (ESP) is mainly used to pump wells with high gas oil ratio. Free gas is separated and vented via a shroud or gas separator. Or, it is compressed using a tapered larger-than-normal pump or specially-designed gas handler below the "normal" pump. Although tapered ESP has been used for decades in petroleum production, few articles have discussed its design. After studying the pressures and flow rates stage by stage using a computer program, the paper presents basic criterion to design a tapered pump.Free gas in pumped fluid stream reduces pump performance, and may cause surging and gas lock. For tapered pumps the free gas effect becomes vital since generally tapered pumps handle considerable amount of free gas. The paper discusses traditional homogeneous model and multiphase pumping model. By comparing pump performances of the two models using examples, the paper presents that the traditional model designs fewer stages and will produce smaller rate than desired rate. Further, without considering free gas effect, the pump above bottom pump may work out of its operating range. For a tapered pump, pumping stability should be checked and pump degradation should be included in stage by stage calculation. Also, fluid flow pattern should be checked to avoid slug flow at the place of pump intake.Also presented are optimal design methods for both single and tapered pumps. Widely used design methods are using desired liquid rate at surface or the liquid rate at pump intake to select a pump with closest best efficiency point. The paper illustrates by examples that the two liquid rate methods fail to design high efficiency when pumping high gas/liquid fluid, and proposes two methods of using total rate at pump discharge and using average total rate. The two design methods will improve a well's pumping efficiency and running life.