Artificial Intelligence and Data Analytics for Virtual Flow Metering

This paper presents a performance evaluation of multiphase flow models when using these models on Virtual Flow Meters (VFM). Recently, VFM simulators have been identified as a technology capable of provide metering backup, monitoring for abnormalities of physical multiphase flow meters and also for production well allocation. Nevertheless, there are just a few studies found in the literature analysing the accuracy of different VFM models applied to multiphase flow metering. In the oil and gas industry it is essential to accurately measure the amount of oil, gas and water being produced by individual wells. Prior to the 1980s, single-phase measurements alone were sufficient to meet the industry standards. However, with the advent of deepwater exploration and production, multiple wells comingling to a single production separator is a common practice in petroleum production for offshore systems. Therefore, the use of multiphase flow meters to account for the production of oil, gas and water from individual wells became evident. This investigation uses field data for more than one well to evaluate the performance VFM simulators. The results obtained from this study shows that VFM models can provide accurate predictions for multiphase flow metering. The simulators evaluated in this study could predict flow rates of oil, gas and water within acceptable levels of uncertainty, with an average absolute error of 20%.

Historically well production flow surveillance has been attracting attention from reservoir engineers. The accurate estimation of individual well contribution, Has profound impact on reservoir management. Often production allocation suffers from multiple issues such as quality of available production data and production rate estimation in case of inaccurate and uneconomical measurements. These issues can be mitigated if the well has accurate, calibrated Multiphase Flow Meters (MPFMs) and Virtual Flow Meters (VFMs). Reliability of digital meters is primarily dependent on regular well testing to keep the model updated and tuned to latest reservoir characteristics. As an industry wide common practice, well tests are performed in a timely manner to ensure to allocate production accurately to each well. But performing solo well tests for subsea wells is not trivial as it may seem. Differed production due to downtime associated with flowing subsea wells to a test separator and inability of mature wells to flow to the test separator result in additional challenges. Under such situations, commingled well tests are performed to estimate well rates. Individual well rates can be estimated using test by difference (TBD) method. The apparent simplicity of the TBD method often results in incorrect estimation of allocation rates as the test conditions and production conditions differs significantly. As a result, the credibility of the forecast and the ability to optimize production are compromised. In this paper a novel application called Commingled Well Test Analysis (CWTA) is reviewed which addresses these aforementioned issues. This integrated application comprises of data loading interface, data visualization interface, core optimization engine and an interactive user interface. To demonstrate the capability, three wells from a deep water conventional wells are analyzed using commingled well tests and well performance parameters (PI, WCUT and GOR) are obtained. Based on the tuned parameters, well rates are predicted and compared against rates obtained from sales meter and MPFM meters. As per the comparison, well allocation rates are validated and health of MPFM meters are assessed. As an additional benefit, proper designing of commingled well tests enable in 25-30% time savings of well testing.

This report documents a project to improve subsea flow measurements to allowthe flow rates of individual wells to be known more accurately. Becauseproduction revenues are determined from flow rates, improved flow measurementreduces the financial risk to stakeholders, including producers and the U.S.government. Improved measurement also helps to improve reservoir recovery. Inthis project, commercially available flow models were evaluated for theirsuitability as virtual flow meters, to augment or replace hardware devices forthe determination of flow rates in deep water wells. The goal of this projectwas to develop methods for evaluating flow models, and to report on theefficacy of these models to predict flow rates. Several flow models were usedin the study, which also includes a survey of the available models. 1. Introduction 1.1. What is a Virtual Flow Meter? Virtual flow meters (VFM) are a method for determining the flow rate of a wellby means of modeling the flow. A VFM model may consist of a single well to anentire field of co-mingled wells. The models are fed data from sensorsinstalled at various measurement points (nodes). Typically pressure andtemperature sensors are used, which are available downhole (perhaps at multiplepoints), at the wellhead, and at the surface. With the pressure and temperaturedata at each node provided as an input, the VFM model computes the flow rate ofthe well. Typically, the model is tuned periodically using available flow data. Once tuned, the model is capable of determining the well flow rate with onlythe pressure and temperature nodal data. The flow models employed with VFMsystems may be built from first principles, but this is not the only method forVFM modeling. Flow models may also be derived from statistical analysis ofmeasurements acquired at different nodes along the production system. An important observation is that VFM software is not something that must beinstalled at the same time as the physical multiphase flow meters, as long ascare is taken to install proper sensors to be used at the various nodes. Thefault tolerant nature of the VFM system is an advantage, since a failed "hard"sensor will reduce the number of nodes, but will not cause a complete loss ofinformation. While VFM technology appears to be maturing rapidly, it is not yet generallyaccepted an equivalent replacement for good physical metering. VFM models areemployed as a back up to a physical meter to be used in case the primarymetering system is unable to function, or as an augmentation of physicalmetering to reduce measurement uncertainty. Some of the commercial VFMs use the technique of Nodal Analysis for the flowrate prediction. This method utilizes available transmitters (pressure andtemperature) and a mathematical model of the complete flow path from bottomhole to the topside facility. This method requires considerable input data, including well and pipeline profiles, the diameters of all components ofsections, sensor locations, fluid properties, choke geometry, etc.

Accurate metering of flow rates and prediction of water breakthrough are important issues in offshore oil production. The multiphase flow rates can be found for instance from frequent well testing, from multiphase flow meters, or from software simulations. Multiphase flow meters are very expensive and so are single-well tests, especially in cases with long tiebacks. On the contrary, software simulations are cheap, they can be made accurate, and simulations can usually be based on existing sensors. Also, software is easy to install, operate, and maintain compared to hardware multiphase meters. In this article we describe the main components needed in a flexible software system for flow metering that can handle sparsely instrumented production facilities. Several sources of implicit information are pointed out, and a tuning strategy that avoids single-well tests is described. We also present examples that show the power of advanced simulations in situations that are not well handled by multiphase flow meters and standard software because of very low flow rates. What makes the situation in the examples even harder is that: There is no available information about the choke, the bottom hole sensors fail, and the temperature measurements are influenced by the seawater temperature. Despite this, good results are obtained. Introduction The offshore oil industry is facing a market where the number of brown fields is growing, and where more and more of the green fields are marginal fields. In addition, many of the new findings are on deep water. These facts all point in the direction of more production networks with long tiebacks, a stronger need for limiting the number of expensive well tests, and a push towards minimizing OPEX in general. The need for reliable monitoring of the production from each well in a production network is therefore continuously increasing. Furthermore, reservoirs may have more than one owner, whereas the various owners may share the same infrastructure and production facilities. In such cases reliable production monitoring is of course highly demanded. A software system for flow rate estimation may satisfy the above needs. Software is relatively cheap, and both installation and usage can be made very easy. Furthermore, software is easily maintained and supervised from remote, whereas hardware, such as a multiphase flow meter, usually needs to be maintained on the site. This is an important issue since many larger green fields are far away from where many of the oil companies' expertise traditionally is situated. Remote access can easily be obtained using standard web browsers and internet technology. However, if the instrumentation is sparse or inaccurate most software systems will not give reliable rate estimates. In this article we will look at how to deal with such problems. We will present the main building blocks for a flexible software system that can handle almost any production network configuration. We also show how inaccurate measurements and what may look like useless information may contribute to good rate estimates.

A multiphase flowmeter capable of adapting to varying well conditions and providing reservoir transient data is an essential tool for reliable production planning and optimization. This is the main driver for the development of a multiphase virtual flow metering (VFM) module, which is intended to be an add-on to the traditional production management system, (PMS), and as a value addition for the operator. Current physical flow metering systems have certain limitations such as a need for extensive calibration, and high capital and maintenance costs. Also, simultaneous monitoring of every producing well can be cost-prohibitive; thus, making it difficult to determine the field production efficiently and accurately. Having limited real-time field data adds a high degree of unreliability to any simulator predictions. The PMS integrated multiphase VFM described in this paper has been designed to specifically address some of these concerns in a cost-effective manner. This VFM system operates on simulated data sets as well as live field data, which are obtained at a much higher frequency to capture even short-duration transients in the field. An additional advantage of this system is that it can be deployed individually for each well, which facilitates single-well production metering. The VFM module, based on the dynamic multiphase flow simulator, has been developed by one of the industry leaders in simulating transient behavior of flow from a reservoir through the pipeline system. Virtual results such as pressures, temperatures, and multiphase flow rates from a digital-twin of the field are used as base results to predict the field flow rates. These predicted flow rates are compared with real-time data from instruments along the well tubing at the bottom-hole and wellhead. The VFM module processes deviations between predicted and real-time data, adjusts for factors such as instrument sensitivities and field data quality, and corrects the virtual flow rates even further towards more accurate predictions. To validate and confirm this, the model also outputs the confidence rating associated with the improved predictions. These predicted results and associated confidence levels are the final outputs from the VFM system. When integrated with the PMS, this VFM module can also configure alerts to the user in the case of any sudden risks or unwanted transients arising from the reservoir such as water breakthrough in a gas well. Upgrading the PMS with the new VFM module will empower the operator with reliable and accurate flow predictions and help overcome the production flow rate uncertainty In addition to removing dependency on field instrumentation, this VFM module will facilitate improved field production forecasting, and can help lead to timely intervention in potential production-loss scenarios caused by unexpected transients.

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.

This paper presents field experiences with the implementation of virtual well metering technology on the North West Shelf (NWS) of Western Australia. This technology is used to obtain well-by-well flow rate estimates using conventional pressure and temperature instrumentation in a wellbore and Christmas tree without the need for expensive multiphase flow meters. Best practices in project execution—including specifications, acceptance testing and commissioning procedures—are presented for deploying this advanced technology. The paper focusses on two NWS gas-condensate developments operated by Woodside Energy Ltd (WEL) on behalf of the NWS joint venture partners: the Perseus over Goodwyn (PoG) project, which is a four well subsea development of the Perseus and Searipple fields that tie back to the Goodwyn A platform; and a three well subsea development for the Angel field. The PoG virtual metering system (VMS) was commissioned in October 2007 and the Angel VMS more recently in February 2009. The paper compares field data and shows that this technology has provided very reliable and accurate flow rate predictions; historical data suggests that monthly reconciliation factors as low as 3–5% can be achieved. Virtual metering systems are a cost effective and reliable means to obtain well-by-well flow rates. Besides enabling better reservoir management, these well metering systems are easily integrated with real-time pipeline monitoring systems to enable reliable subsea operations. An integrated virtual metering and pipeline management system that includes look-ahead forecasting capabilities and guidance for real-time flow assurance on operational issues, such as hydrate formation and detection of restriction, is being developed for the Pluto field.

Flow rate measurement uncertainty analysis is a key methodology for addressingproduction allocation, reservoir performance optimization, operationalquestions, and regulatory issues. Until now, no unique collection of procedureshas been available to estimate the total system uncertainty associated withmultiphase flow meters, well test separator systems, and the pipelinesconnecting them, especially for commingled flow configurations. A tool to dothis would assist industry stakeholders in understanding the uncertaintyassociated with fiscal allocation of production, reservoir management, andforecasting processing facility operations. With this need in mind, and the support of several offshore operators and DOEthrough the RPSEA program, the team developed a software tool with auser-friendly interface for predicting total network uncertainties for systemswith subsea multiphase flow meters (MPFMs). The tool accounts for meteroperating conditions, in-situ pressure - volume - temperature (PVT) properties, system configurations, and flowline/riser effects. It is anticipated that thistool will be attractive to all industry stakeholders, in order to moreequitably allocate production and optimize reservoir performance. Thebackground of the tool's development, an overview of use cases, and lessonslearned from the effort will be presented. Introduction Flow rate measurement uncertainty analysis is a key methodology for addressingproduction allocation, reservoir performance optimization, operational issues, and regulatory requirements. Unfortunately, no unique collection of proceduresis currently available for predicting the total system uncertainty associatedwith multiphase flow meters (both subsea and topside), well test separatorsystems, and the pipelines connecting them, especially for commingled flowconfigurations. This lack of tools for understanding and predicting uncertaintycauses significant problems for all parties involved, especially for fiscalallocation of production, with reservoir management, and with forecasts foroperation of process facilities. A software tool with a user-friendly interface for predicting total networkuncertainties for systems with subsea multiphase flow meters (MPFMs) wasdeveloped as part of RPSEA 07121-1301. The tool accounts for meter operatingconditions, in-situ PVT properties, system configurations and flowline/risereffects. It is anticipated that this tool will find use among vendors, oilindustry operating companies and regulatory agencies, in order to moreequitably allocate production and optimize reservoir performance. Motivation Accurate flow rate measurement has become a critical issue for the oilindustry, especially for offshore and subsea developments. Multiphase flowmeasurements are traditionally made using a well test separator andsingle-phase metering system topside. In recent years, multiphase flow metermeasurements topside and subsea have been accepted for well tests, when themeters are operated within meter specifications and near calibrated conditions. However, no reliable uncertainty models that couple multiphase flow in flowlines with the separator and meter uncertainty under flowing conditions existeduntil now.

The difficulties associated with producing heavy oil have discouraged operators from developing the Atlanta field in the Santos basin offshore Brazil, despite more than 1.5 billion bbl of oil in place. The water depth in the area is more than 1,500 m, which makes operations even more challenging. Because Brazil has set aggressive production targets for the next decade, new interest has been given to the field, and a consortium of E&P operators began to reassess the field. Well deliverability and test data are crucial to field development planning. Well test operations were planned with a multienergy gamma ray and venturi multiphase flow meter used as contingency. During the well test operations, the foaming propensity of the produced oil made it almost impossible to distinguish an interface between liquid and gas in the separator or tank, rendering the standard equipment useless. Only in the second test were some tank measurements available. The measurement principle used in this multiphase flow meter, however, is not sensitive to foam or emulsion because they respond to the atomic-level composition of the different components of the mixture independently of their arrangement, providing accurate flow rate measurements. We detail the behavior of the multiphase flow meter during the well tests in the Atlanta field and the challenges caused by foaming oil. In the case of standard oils, the measurements are not sensitive to the viscosity value. However, in the case of high viscosities which lead to low Reynolds numbers, the viscosity value can drastically affect the results. In this case, some solvents were injected during the well test to reduce the liquid viscosity, and we present the consequences on the multiphase flow meter. We also compare the multiphase flow meter results to the gas/oil ratio measured in the laboratory on downhole samples from the same reservoir, to the water cut measured manually during the operations and to the tank measurements. Finally, we present some recommendations on the use of multiphase flow meters for heavy oil well tests.

Accurate oil, water and gas flow rate measurements from individual wells are essential in order to properly manage both the wells and reservoirs, as well as to obtain reliable data for production performance monitoring, optimization, allocation and simulation models1, 2, 3, 4, 5. Over the past three decades, there has been great advancement in the multiphase metering technology. These advancements have resulted in a significant improvement in measurement accuracy as well as in reducing the physical size of these meters which is a crucial element in limited-space environments as in offshore platforms. The intent of this paper is to present results of a compact Multiphase Flow Meter (MPFM) " PhaseWatcher?? based on information gathered from Saudi Arabia, where more than one hundred meters have been installed so far in several fields covering wide ranges of fluid properties and operating conditions. Moreover, the paper will discuss in detail the effect of crude sourness (H2S concentration) and pressure on the meter's measurement accuracy. Multiphase Flow Meter (MPFM) Design The PhaseWatcher is designed to measure the total volumetric flow rates of oil, water and gas at line conditions. These flow rates are converted to standard onditions via a pressure-volume-temperature (PVT) package, which can be either the default Black Oil Model or a specific model derived using a client supplied PVT data. The meter comprises of five basic components, Fig. 1:A Venturi meter with pressure transducers across it to measure the differential pressure between the inlet and throat of the Venturi.A nuclear dual energy fraction meter consisting of a Smart Detector and Barium Source, measures the count range of photons transmitted from the source to the detector at two different photon energy levels (the high energy level is used to measure the density of the mixture, while the low energy level is used to calculate the water-oil ratio).Process fluid temperature transducers, which measure the fluid temperature upstream of the Venturi section and the ambient temperature.A Blind Tee Static Mixer, used to homogenize the flow stream ahead of the Venturi meter.A process flow computer used to manipulate the measured data.

Multiphase flow metering is very important in the oilfield. We construct four new liquid metering models (Falling Model I, Falling Model II, Open Channel Model and Element Resistance Model) and a gas metering model based on the online multiphase flow metering equipment without separation. The experimental study was carried on indoors at the multiphase flow metering equipment, and the model coefficients can be figured out by the method of date classification. We can figure out the error of each phase, and evaluate all the metering models. Through errors analysis, the average error of the liquid metering models can be within 10%. The error of gas metering model can be controlled within 20%. The experiment results proved that these metering models can be used in the multiphase metering with different viscosity. The metering precision is rather high in the wide range of gas phase and liquid phase flow rate. And it fits in with outdoor application.

Objectives/Scope: During the period of two years the difference between sum of daily oil flow rate measurements of each oil production well using multiphase flow meter (MPFM) and cumulative daily oil production rate measured by custody transfer meter increased overall by 5%. For some wells inaccuracy of MPFM liquid rate measurement could reach 30-50%. The main goal of this research was to improve the accuracy of multiphase flow meter production rate measurements. Methods, Procedures, Process: More than 80 oil production wells were involved in the research, more than 100 flow rate tests were carried out. Machine learning methods such as supervised learning algorithms (linear and nonlinear regressions, method of gradient descent, finite differences algorithm, etc.) have been applied coupled with Integrated production modelling tools such as PROSPER and OpenServer in order to develop a function representing correlation between MPFM parameters and flow rate error. Results, Observations, Conclusions: The difference between cumulative daily oil production rate measured by custody transfer meter and multiphase flow meters decreased to 0.5%. The solution has been officially applied at the oil field and saved USD 500K to the Company. The reliability of the function was then proved by the vendor of MPFMs. Novel/Additive Information: For the first time machine learning algorithms coupled with Integrated Production modelling tools have been used to improve the accuracy of multiphase flow meter production rate measurements.

During the past few years, Saudi Aramco has installed and field tested eight different types of multiphase flow meters (MPFM). These newly developed, compact MPFM are targeted for wellhead installation at remote onshore fields and unmanned offshore platforms, where weight and space are major concerns. MPFMs could provide continuous well test data, which would lead to more accurate production allocation and better reservoir management. The application of MPFMs in Saudi Aramco’s production operations, if proven successful, will provide continuous online well production monitoring, and eliminate large conventional test separators, test lines, and offshore test barges. As a result, tremendous economic savings could be realized due to the significant reduction in capital and operating expenditures associated with well testing activities. The test installations cover a wide range of multiphase applications from over six different oil fields. The objective of the field testing program was to establish the ability of each meter to accurately measure the three production phases (oil, water and gas), and to determine meter reliability in a field environment. Field test results of the multiphase meters are compared to reference conventional test separators. The paper also presents the current status of multiphase metering technology, and discusses in detail the multiphase metering evaluation program at Saudi Aramco.

The need for multiphase flow measurement in the oil and gas production and petrochemical industries has been significantly increased over the last few years.Reliable measurements of the multiphase flow parameters such as void fraction, phase concentration, phase velocity and flow pattern identification are important for accurate modelling and/or in the operation of multiphase systems.Although many multiphase flow meters were recently developed, challenges in measuring multiphase flow components remain unresolved.Therefore, extensive research efforts were spent in designing accurate multiphase flow meters and several meters are currently under development worldwide.However, due to the complexity of the multiphase flow mixture and in some cases when three or more phases co-exist, it is impossible to adopt only one technique to develop a multiphase flow meter.Consequently, the integration of multiple sensors, based on several measurement techniques, found to be the optimum solution for accurate multiphase flow metering.The main objective of this study is to evaluate existing multiphase flow measurement techniques for the potential integration in a multiphase flow metering device.

Proper testing and measuring of a gas-condensate well is essential to ascertain the state of the hydrocarbon system at reservoir conditions and to plan the best production and recovery program for the reservoir. At surface, the volumetric measurement of three phase flow of a wet gas well has been considered challenging. Existing conventional metering devices and ordinary multiphase flow meters (MPFMs) are usually incapable of providing accurate measurement of flow rates in a dominating high gas volume fraction. Portable separators equipped with liquid gauge tanks are still considered accurate, but are bulky and expensive. This paper discusses the results obtained from tests conducted using multiphase flow meters in wet gas-condensate producers at a wide range of flowing conditions. The meters were installed in conjunction with a regular three-phase test separator, and the objective of the tests was to measure meter accuracy in comparison with the data obtained from the conventional test separator. Obtaining accurate three-phase data in wet gas producers poses a significant challenge for the majority of conventional multiphase flow meters, because of the high-gas volume fraction (95 % and above) nature of the wells. The paper also discusses some lessons learned, challenges and uncertainties associated with accurate flow measurement of a wet gas well encountered throughout the testing, as well as other important observations. The tests were conducted by Saudi Aramco over a four-month period using two MPFMs (A and B) in five different wells, spread out throughout the Ghawar field.The tests were conducted in wells producing at rates ranging from 10 to 40 MMSCFD, and condensate-gas ratios ranging from 30 to 320 Bbls/MMSCFD. Three tests were conducted in each gas producer, totaling 15 tests. The testing concluded that both meters require technological upgrading to meet the acceptance criteria in measuring the three phase flow with acceptable accuracy.