Using multiphase flowmeters in field operations has now become a widely accepted practice especially in the range of Gas Volume Fraction (GVF) of 0 to 85%. There is still some doubt about the performance of this type of device especially in the High (92–96%) or Very High GVF (96–98%) ranges. Most of the purchasers put a cut off in the GVF range of 85–92% following the type of technology. These criteria are often based on past experience or special cases, which could be several years old. A split in terms of naming is even commonly accepted in the multiphase business between Multiphase Flow Meter and Wet Gas Meter. With the recent dedicated Gas Mode developed by Schlumberger, it is now possible to test both gas and oil wells with the same hardware. The focus put in the past few years on a combination of robust and simple measurements (Venturi and gamma ray) in multiphase flow-metering solutions for any type of well based on the advantages and benefits of the industry recognized Vx* Technology. In this paper, we will review the benefit of the combination of Venturi and gamma ray fraction meter and its application to gas well testing. Today, the use of the entire information of a gamma ray spectrum gamma ray (more than 2 rays) allows a real-time or an a posteriori quality control and improvement of the overall performance of the meter in any type of conditions. This statement will be presented through a campaign of tests done in South America. First of all, we will show how the entire information of a gamma ray spectrum permits a quality control in real time, and allows tracking of fluid composition change over time. Then we will focus on high producing gas wells clean-up that have been successfully tested using the Vx technology in Gas Mode in 2005. Exceptional results against conventional test separator have been presented in previous paper (Ref [10]) with a maximum error of 2–3% for the gas. The current paper will also put a special emphasis on the salinity change. Introduction A 3 phase flow measurement requires as minimum information the velocity for each phase (i.e. 3 velocity measurements) and 2 holdups (i.e. fractions) knowing that the sum of the 3 holdups is equal to 1. Numerous techniques exist to try to achieve these 5 measurements ([Ref [1, 2, and 9]). Meanwhile, a multiphase flowmeter is measuring at line conditions the different flowrates; therefore it is necessary to associate two other measurements for PVT Conversion from line to standard conditions (i.e. Pressure and Temperature Sensors). The most common technique used in the industry to measure flowrates is the Venturi (or differential measurements); all manufacturers are using one or several Venturi and most of the time coupled with a density nuclear measurement. The fraction measurement techniques are more versatile and we could split them between low energy gamma ray measurement, the most common one, and electromagnetic measurement. The former is the simplest option to get the multiphase meter as less complex as possible. Indeed, the high energy gamma ray being already present for density measurement, the addition of a second radionuclide or an appropriate chemical source could provide the two energy levels required to do the fraction measurement [Ref 2]. This leads to a compact and efficient solution.
Dual-energy spectral gamma ray / Venturi multiphase flowmeters present an efficient and cost-effective means of testing wells in many field applications. A simple, efficient and quick procedure optimizes the utilization of these types of multiphase flow meters for well testing. This paper presents the field operating procedures for installing and using multiphase flowmeter and gives practical recommendations for performing well tests with or without a reference, such as a separator. The analysis of 415 multiphase well tests performed worldwide has provided some insights into the accuracy achieved in the field and has led to some recommendations for the test design. The ability of a multiphase flowmeter to perform a measurement in the absence of a flowing reference is essential to well testing in most applications. Furthermore, the high mobility of the equipment (with up to three wells tested in three different locations per day) allows a very efficient and short turn around time for installation and operation. The parameters required to perform the setup of a meter fall into two categories: meter static empty pipe reference and fluid properties. A detailed review of each parameter is presented along with its sensitivities when determining the flow rates of oil, gas and water. A description of the field procedure used to determine each setup parameter is provided and a series of field examples are presented that illustrate the efficiency of using multiphase flowmeters for well testing. Introduction The use of multiphase flowmeters in well testing is not new. Early developments (in the 1980s) of multiphase flowmeters have been geared towards the testing of wells mostly in the United States. In the early 1990s, the engineering of multiphase flowmeters took a form more oriented towards pure instrumentation and metering applications, with many operating companies metering departments and research centers working in close collaboration with various suppliers to advance the technologies.1–18 Key technology breakthroughs, mostly in the determination of fractions combined with a better understanding of multiphase flow dynamics, have improved the overall confidence in the techniques and led several operators to implement field applications of multiphase flowmeters. Most of the meters deployed in the oil field to date are installed permanently in production systems. Such applications will not be discussed here. We will focus on the challenges of mobile well testing operations, supplied as a full service package by a service company. Review of benefits of multiphase flowmeters Traditionally well testing is performed using single-phase flowmeters installed on the oil, gas and water outlet of test separators. Large pressure vessels, important hydrocarbon inventory in piping and separator bodies, heavy lift, large rig-up and operating crews have been some of the chores attached to well testing. Refs. 16 and 19 illustrated the benefits of multiphase flowmeters over test separators in some field applications. Although some tradeoffs are inevitable, overall multiphase flowmeters bring an efficient solution to well testing measurements. Their main benefits are gains inSafetyLogisticsDuration of the operationData quality
Representative reservoir fluid sampling and characterization has become increasingly important over the years. With exploration, appraisal and development activities moving into marginal fields and more challenging environments, accurate fluid characterization becomes more critical. This can be said for the formation tester, DST and multiphase sampling and fluid characterization environments with the most challenging area in recent years arguably being the multiphase environment. Multiphase flow meters have been accepted for several years now by the industry. Their use in permanent or well testing applications has been growing rapidly. In many cases, multiphase flow meters have replaced the separator for flow rate evaluation, but some fundamental needs from the client were not addressed properly, such as the ability to collect representative samples for phase-behavior characterization. Moreover, metering accuracies has been questionable in many cases (at very high GVF or in wet gas conditions, high pressure or /and high temperature).This paper focus on the Multiphase Active Sampling Device Service (MASS), a fluid sampling and analysis service that can be provided with the Vx multiphase metering technology with the objective of collecting representative samples, isolating and analyzing each fluid phase, and providing data from the analysis to input to the Vx acquisition software data to obtain more accurate flow rates. The collection of phase representative samples also opens the opportunity for a full recombination PVT study to be performed using the improved recombination ratio at line conditions from the multiphase flow meter. This dedicated multiphase fluid sampling and analysis system, combined with Vx technology provides flow rate better and fluid property than to a conventional test separator system.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn early 2002, Abu Dhabi Company for Onshore Oil Operations (ADCO) ran a production-logging program on a high-performance onshore well with an intensive surface welltesting program. This involved running a multiphase flow meter in combination with a calibrated gauge tank and a test separator, in order to qualify the metrological performance of the multiphase flow meter. The objectives were to determine well productivity, establish the flow profile of the reservoir, and assess the performance of the multiphase flowmeter.This paper describes the benefit of advanced multiphase flowmeter technology and the verification of its performance accuracy against production logs and surface equipment.In addition to the accuracy computations, the repeatability and linearity of each measuring device were also evaluated. Examples will be given.The paper also illustrates how this multiphase flowmeter technology improved the diagnosis of the actual well response.
Inaccurate PVT information has been shown to contribute significantly toincreased uncertainty for subsea multiphase and wet gas meters when determiningstandard conditions flow rates. Typically, subsea meters have been set-up usingPVT information gained from samples taken during drilling. Rarely has this databeen updated, due to lack of access to quality representative samples. Thispaper addresses the issues regarding access to well stream fluids, the abilityto capture representative samples, sample handling and storage, and the dataneeded to recombine the samples, and possibilities to implement solutions tothese challenging conditions. Multiphase meters serve as the operator's eye into the subsea multiphase flowprocess and provide volumetric flow rates and split between the oil, water andgas phases along with a number of measured and calculated values. The dataprovided by the meters is used for flow assurance, allocation, and productionmanagement and to gain understanding of the reservoir structure, hence theimportance of maintaining the quality of the measurement over time. Themeasurements from any inline meters are reported at line conditions, where themeasurements are taken, usually near the subsea tree, but the operator usuallyrequires the meter to provide flow rates in Standard Conditions as well. Theseline conditions measurements are then converted to standard conditions usingeither a set of correlation (black oil model usually) or a tuned Equation ofState (EOS). Depending on the fluids, the method used can have an impact of upto +/- 30% uncertainty at standard conditions (Joshua Oldham, Exxon Mobil, atSubsea Tieback 2008). In order to reduce this source of uncertainty, the EOS must be updated asneeded. If wells are commingled subsea the only way to gather the informationneeded is to sample the fluids at meter conditions in a representative stateand recombine them in the laboratory. The remainder of the paper will describe the tools and methods needed toachieve this as developed by Schlumberger and Framo Engineering.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.