The paper presents the field performance of mobile multiphase flowmeters in more than 500 well tests during the last three years. The field tests were conducted on land or offshore in a wide range of field operating conditions, such as high flowing pressure, heavy oil, viscous fluids, gas and wet gas, gas volume fraction ranging from 10% to 99.6%, and water to liquid ratio frcm 0 to 100%. An in-depth analysis of the lessons learned shows the benefits and limitations of the technology in comparison to the traditional test separators and illustrates the expected range of accuracies that can be readily achieved in the field environment. Statistics from over 600 comparison tests provide a complete understanding of the accuracies of oil, gas, and water flow rates achieved with the multiphase flowmeter. The dual-energy spectral gamma ray venturi multiphase flowmeter requires the measurements of few basic well site fluid properties. A procedure, detailed in the paper, explains the utilization of a field kit specifically designed for this application when no prior information of fluids is available, which is frequently the case in well testing in new areas. The paper presents how the specifically engineered test-design software provides a rapid-decision tool to the selection of the best well testing solution (multiphase flowmeter or test separator). Finally, some operational recommendations for performance of well tests using multiphase flowmeters shares the experience acquired in these 500 operations performed worldwide.

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

Cleanup operations are often challenging to predict. The review of the major physical phenomena governing the behavior of a well cleanup sheds light on some important considerations to be taken to design and realize such operations. An optimal cleanup program will depend on the well construction processes, the lithological factors and the interaction between the drilling fluids and the formation, active sequencing of chokes. The coupling of these complex physical operations can be non-intuitive. A modeling approach is proposed and validated through comparison with field data. The design of an optimal cleanup program is hampered coupling of two issues: the existence of formation damage due to the invasion of mud in the near well-bore area and the transient well bore phenomena associated with the replacement of drilling or completion fluid with lighter hydrocarbons. This paper investigates the integration of transient simulation of near wellbore multiphase phenomena with complex wellbore dynamics and provides recommendation on cleanup designs. The success of a wellbore cleanup is gauged in different ways, depending on the lithological, drilling and operational environments. Metrics of performance such as duration of the operation, productivity, recovery of loss fluids are commonly used. We tackle the global issue with a predictive model specifically tailored to cleanup operations in a layered system that considers: An internal mud cake (which is formed by mud solids intrusion into the formation) An external mud cake (formed at the interface well / formation) A mud filtrate invaded zone Potential perforations Dynamics of the multiphase (and multi-component) wellbore flow Flow control devices The paper discusses the laboratory validation of the near well bore model against dynamic core flooding and transient return permeability experiments. Comparisons against field data obtained with high speed multiphase flowmeter or dynamic production profiles further enhance confidence in the simulations. A number of recommendations for cleanup designs are provided considering some of the challenging constraints such as: Operational constraints: limited storage volume, rig time, pressure drawdown limits (collapse), noise, rates Fluids limitations: avoiding drawing pressure below bubble / dew points Geomechanics limitations: max drawdown or avoiding tubing collapse or protecting other completion elements such as screens Lithological challenges: multilayer reservoirs and horizontal wells where it is necessary to clean all layers / drain. Large drilling losses resulting in perforation channels not bypassing totally the mud filtrate invasion zone (and sometimes the internal mud cake area) The analysis of the sensitivity of various model parameters confirms the need for robust cleanup designs that takes into account the actual uncertainties of the well construction process and of the formation heterogeneities and near wellbore characteristics. This study demonstrates that the principal cleanup characteristics are essentially dependent on properties of the drilling and completion fluids. It is possible to give some practical operational recommendations for improved cleanup such as zone selectivity, choke sequencing and pressure controls. The utilization of temperature variations at the on-set of the cleanup also provides important knowledge to the interaction of the drilling fluids and completion fluids with the formation prior to the test. This information can be used to optimize the next well. The monitoring in real-time (or in-time) of the downhole parameters such as pressure, temperature can significantly help to reduce the uncertainty of the cleanup operation and decrease substantially the rig time.

Quality of well testing in highly productive reservoirs directly depends on the pressure-gauge placement in the wellbore. This paper documents the impact of the placement of downhole gauges on pressure transient analysis (PTA) for high-productivity reservoirs. The article illustrates cases where this latetransient behavior is strongly influenced by temperature effects, which can lead to significant errors if not considered during the interpretation process.Although the correction of measured pressure to datum is possible by proper modeling of the influence of non-isothermal effects on the test string and the produced fluids caused by temperature changes, it is preferable to avoid this situation by suitable gauge placement. This greatly facilitates a more accurate interpretation of data using PTA with a reduced uncertainty in the definition of the appropriate reservoir model to use. Proper modeling during the test design of these temperature effects on the correction of pressure to datum also allows the determination of the resulting uncertainty pressure variations and the selection of the optimal test-string design, with consideration made to the expected temperature changes, fluid present in the wellbore, and range of productivity. Reconstruction of pressure is also possible despite a high level of resulting uncertainty.A workflow for reconstruction of pressure data taking into account temperature effects is proposed. We emphasize that such corrections cannot substitute the correct pressure measurement for successful well-test data interpretation. Present gauge technology allows proper test design and correct placement of pressure and temperature gauges in close vicinity of the interval of interest, to avoid or minimize potential problems related to the reconstruction of the measured pressure to datum.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractTraditionally, well allocation and fiscal allocation have been performed on the basis of test separator information. The technology breakthrough of multiphase flowmeters brings new solutions to allocation solutions. These new flow rate measurements have demonstrated some unexpected well behavior. These dynamic effects (instability, slugs) have shed light on the origin of some back-allocation factor issues experienced in some fields. The paper discusses actual causes for large back-allocation discrepancies and provides examples of challenges to standard test separator. This paper also presents the decision strategies related to the implementation of multiphase flowmeters to determine allocation issues. The paper discusses the impact of uncertainties of multiphase flowmeters on the overall fiscal allocation and provides recommendations on installation methodologies and screening processes to make best use of the dynamics of these new measurements.The understanding of the different needs for well test information and allocations is illustrated and the impact to the allocation factors is shown. The distinction between wellspecific tests and diagnostic information from pad/manifold fiscal allocation is important to the hardware selection process and to the back-allocation issues. The impact of the frequency of the measurement is also quantified. The paper concludes with a series of recommendations to improve back-allocation factors on existing installations