Individual Phase Flow Rates Research Articles

A Kalman estimation based oil–water two-phase flow measurement with CRCC

Measuring the individual phase flow rates of oil–water two-phase flow is an important issue in process industries. A Conductance Ring Coupled Cone (CRCC) meter is presented for this task, and conductance ring array (CRA) was installed in front of CRCC for results comparison. A CRCC provides multiple outputs regarding the flow rate and water holdup by implementing a pair of conductance rings in an annular flow channel formed by a long-waist cone and pipe wall. Three outputs, contracting differential pressure Δptp, overall differential pressure δptp and dimensionless conductance Va∗, are fused by a Kalman filter to estimate individual flow rate of oil (Wo) and water (Ww) simultaneously. A transition model with state vector [Wo,Ww]T is established based on the random walk assumption of two-phase flow, and an observation model is established with Δptp and δptp based on the separated flow assumption. The parameters of these two models are optimized with the Expectation–Maximization (EM) algorithm under each experimental condition. The present method treats the two-phase flow a dynamic process with a dynamic state estimation method. The estimation results demonstrate a dynamic response of CRCC to the change of flow conditions. The overall accuracy of the oil flow rate estimation is 2.3% and for the water flow rate is 4.8%. The comparison of the proposed method with CRCC model based dynamic/static estimation, as well as the CRA model based estimation, indicates that the proposed sensor structure improved the estimation accuracy by measuring the water holdup in annular channel. The dynamic estimation can also improve the estimate accuracy by incorporating dynamic fluctuation and unknown correlations with inferential parameters through optimizations. More accurate and reliable estimates can be obtained by optimizing the transition and observation models with profound multiphase physical flow models.

Investigation of the exploitation of a fast-sampling single gamma densitometer and pattern recognition to resolve the superficial phase velocities and liquid phase water cut of vertically upward multiphase flows

The application of a single gamma densitometer unit to determine both the phase volume fractions and velocities to yield the individual phase flow rates of vertically upward multiphase flows was investigated. A fast-sampling (250 Hz) gamma densitometer was installed at the top of the 10.5 m high, 108.2 mm internal diameter, stainless-steel catenary riser in the Cranfield University multiphase flow test facility. Gamma radiation attenuation data was collected for the caesium-137 radioisotope-based densitometer for a range of air, water and oil flow mixtures spanning the facility’s delivery range. Investigation of the gamma densitometer signal response identified the presence of quasi-periodic waveforms in the time-varying multiphase flow densities. Classification of the multiphase mixtures’ flow regimes was investigated through the analysis of the probability distributions from the gamma densitometer data and self-organising feature maps. Two pattern recognition models were developed: a single feedforward multilayer perceptron and a multilayer hierarchical flow regime specific model. The neural network models were exploited to extract the individual phase flow rates of the multiphase mixtures from the quasi-periodic density waveforms inferred by the gamma densitometer measurements. Initial results yielded superficial phase velocity and water cut measurements to within ±10% based on flow regime specific correlations.

Production-Well-Testing Optimization With Multiphase Flowmeters

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 101475, "Production-Well- Testing Optimization Using Multiphase Flowmeters," by M. Metwalli Hassan and M. Bekkoucha, Adco, and M. Abukhader, Schlumberger, prepared for the 2006 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 5-8 November. Production testing by use of portable multiphase flowmeters (MPFMs) was implemented in Abu Dhabi Co. Onshore Oil Operations' Field B. The objectives were to quantify the water and gas production, evaluate the performance of slugging and intermittent wells for procurement actions, evaluate the production-test data measured with conventional test separators, and improve the testing duration and strategy. The program included a set of elements to qualify the MPFM results before use and considered parallel testing with conventional separators to enable fair comparison of results. Introduction Field reports indicated that the actual production volumes of oil, water, and gas from the B field do not match theoretical volumes calculated from well-test results measured with test separators. This mismatch of production data is reflected in the accuracy of reconciled production allocation on a per-well basis and the reservoir basis. Production performance and well-diagnostics analysis were other issues that affected reservoir-management decisions and proactive procedures, especially for high-water-cut and high-gas/oil-ratio (GOR) wells. Monitoring of the slugging and intermittent wells also was a problem for test separators. Accurate production data are required for numerical simulation, reserves calculations, and optimization of reservoir-data acquisition. MPFM Application. The MPFM testing campaign in the B field was implemented initially in oil-rim reservoirs similar to that shown in Fig. 1. Wells in these reservoirs have severe reservoir-pressure depletion, high water cut (10 to 60%), and GORs ranging from 2,000 to 20,000 scf/STB. The oil rims are thin reservoirs (30 to 60 ft) and are narrow. Oil rims are saturated-oil reservoirs, and both the gas cap and the oil zone are produced without pressure maintenance. Therefore, most of the wells in these reservoirs experience either intermittent or slugging production. Testing these wells with conventional separators indicated unstable production rates and erroneous measurements of oil, water, and gas rates. Accordingly, these wells were given priority for testing by MPFM. MPFM Used The meter is a portable phase-tester venturi meter. It is an in-line MPFM capable of operating under a large variety of conditions. The venturi meter has two main sections: the measuring section and the data-acquisition flow computer. The measuring principle is based on a total-mass-flow rate measured with a venturi meter. The individual-phase fractions (oil, water, and gas) are measured with a dual-energy gamma-fraction meter. The data are processed in the data-acquisition flow computer, which computes the line pressure and temperature and the individual-phase flow rates.

G102 差圧変動波形に基づく気液二相流の各相流量同時測定法の開発(2)(GS1 混相流・振動流,一般セッション)

This study proposes a measuring method for individual phase flow rates of gas-liquid two-phase mixtures in a circular pipe. First, the time-variations for pressure are measured at three points around a vortex generator mounted in the pipe under the known flow rates. Secondly the features of the differential pressure fluctuations, such as the mean and the standard deviation, are calculated to construct a database relating the flow rates with the features. Consequently, if the differential pressure fluctuations are measured under unknown flow rates, the individual phase flow rates are successfully identified from the database.

G102 差圧変動波形に基づく気液二相流の各相流量同時測定法の開発(1)(GS1 混相流・振動流,一般セッション)

G102 差圧変動波形に基づく気液二相流の各相流量同時測定法の開発(1)(GS1 混相流・振動流,一般セッション)

Imaging technologies in oilfield applications

In this paper, we describe some recent imaging technologies developed by Schlumberger for oilfield downhole multiphase flow production logging (PL) and cross-well electromagnetic (EM) survey applications. FloScan Imager (FSI™) has been introduced as a 3-phase oil/gas/water flow PL tool for deviated and horizontal wells. FSI sensors can map fluid velocity and holdup profiles along a vertical diameter of the wellbore at every survey depth, enabling a robust estimate of the individual phase flow rates in complex flow regimes. The cross-well EM survey is based on cross-borehole induction logging technique and provides resistivity distribution at a reservoir scale. It is a useful tool for reservoir management and is most effective in dynamic fields where fluid saturations are variable in time and space. The tool can be used to identify (water or steam) flooded and bypassed regions. By monitoring changes in the resistivity spatial distribution with time, cross-well EM survey is very effective at mapping inter-well temperature and structure. Some field examples are shown for both FloScan Imager PL tool and cross-well resistivity imaging survey.

Correlative Mapping Method for Measuring Individual Phase Flow Rates in Air-Water Two-Phase Flow Based on Stochastic Features.

This paper presents a correlative mapping method for measuring individual phase flow rates in an air-water two-phase flow. The method consists of the extraction of stochastic features from differential pressure waveforms, construction of a data base by making contour maps of the feature vectors, and flow rate identification based on a pattern recognition technique using the data base and measured pressure waveforms. To enable the metering device to be portable, pressure is detected by a Venturi tube installed just downstream of an offset elbow, by which the mixture is forcibly mixed, and which brings about a definite flow state depending on a pair of phase flow rates. Experiments in an air-water loop showed that individual phase flow rates can be measured with an accuracy of 4.7% for the air phase and 4.0% for the water phase, and that the method appears to be applicable for measuring production rates at well heads iii offshore oil fields.

Correlative Mapping Method for Measuring Individual Phase Flow Rates of Air-Water Two-Phase Flow Based on Stochastic Features.

We present a correlative mapping method for measuring individual phase flow rates of an airwater two-phase flow. First, we extract stochastic features of a fluctuating pressure difference in a Venturi tube placed just downstream of an eccentric elbow, and second, we evaluate its individual phase flow rates based on pattern recognition for a data base, which is constructed beforehand, Experiments in an air-water loop showed that individual phase flow rates can be measured within an accuracy of 4.7% for the air phase and 4.0% for the water phase, and that method is applicable to the measuring management for production rate at well heads in offshore oil fields.

A Software Technique for Flow-Rate Measurement in Horizontal Two-Phase Flow

Summary This paper presents a software technique for measuring individual phase flow rates in two-phase flow. The technique is based on the extraction, classification, and identification of stochastic features from turbulent pressure and void-fraction waveforms. Experiments in a horizontal air/water loop showed that a set of stochastic features is uniquely related to the individual phase flow rates. The software flowmeter is calibrated in situ by compilation of feature sets related to individual phase flow rates in a data base. On-line flow-rate measurement is made by a pattern recognition technique that identifies the best match to the measured feature vector from the calibration data base.

Multiphase Flow of Water, Oil and Natural Gas Through Vertical Flow Strings

Introduction Multiphase flow through vertical pipe is encountered in many engineering installations. In petroleum, chemical process, nuclear engineering and many other industries, problems associated with simultaneous flow of two or more phases through vertical pipe have been of interest for a long time. This interest has increased considerably during recent years due to applications to new processes in petroleum production and refining and to problems of steam generation and heat removal from nuclear reactors. One prominent example of vertical two-phase flow is provided by the gas-lift process where oil, water and gas flow simultaneously. If the pressure profile in a gas-lift well can be predicted within reasonable accuracy, it would be possible to get good estimates of the power required to lift the oil, the optimum depth, the pressure and the rate at which to inject gas. Furthermore, the effect of production rate and tubing sizes on these quantities can be evaluated before any design decisions are made on the installation and operation of the flow string. The majority of experimental work available in the literature deals with two-component systems where individual phase flow rates in and out of the pipe remain constant. The general problem of prediction of pressure drops in multiphase flow systems is very complicated. The co-existence of numerous flow patterns of widely different geometry and mechanism, conditions of surface instability and the nature of force fields acting upon the system are among the major difficulties commonly encountered. The classical approach of fluid dynamics which would be based upon the formulation and solution of Navier-Stokes equations has been found by many investigators completely devoid of any hope of success -- not only because of inherent nonlinearities but also because of insurmountable analytical difficulties standing in the way of setting up the boundary conditions. The presence and effect of interfacial forces on multiphase flow systems further complicate the theoretical approach. For these reasons, many investigators choose to adopt semi-empirical if not purely empirical approaches in order to obtain solutions of engineering utility.