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Abstract A sensor capable of measuring the flowrates of fluids under pressure up to 15000 psi (103.4 MPa) with an accuracy of +/- 1% of the full scale, adjustable between 5.0 and 30.0 bbl/mn (0.79 and 4.77 m3/mn) in a standard 3" line is presented. The device is completely non intrusive and operates with any kind of fluid encountered in the oilfield environment irrespective of its properties (e.g. electrical conductivity, rheology, presence of solid particles). Applications of the flowmeter are discussed. Besides better control and evaluation of pumping operations, in cementing, stimulation and drilling, the readings are used to ascertain important parameters such as the bottom hole pressure or the total volume pumped. Another application more specific to cementing concerns mud removal. In addition, when the device is coupled with a flowmeter on the return line, differential flow measurement can be made permitting circulation losses and well kick detection. Introduction Accurate flow measurement in the oilfield is a difficult problem because of the wide variety of fluids involved and the severe environmental conditions. In pumping services, the fluids range from clean water to abrasive cement slurries and proppant ladened oil or water based gels. Emulsions, acids and cryogenic fluids are also often encountered. In addition the line pressure can be very high, up to 15000 psi and the flow is strongly pulsed due to the positive displacement triplex pumps. Drilling operations are somewhat similar in this respect. The properties and nature of drilling fluids as well as the conditions under which they are pumped makes the measurement of the flowrates difficult. In production operations, the problem of multiphase flows is common and the use of conventional measurement devices like, for instance, turbine flowmeters is hampered by the presence of solid particles. Changes in viscosity of the fluids is also detrimental to the accuracy of the measurement. Nonetheless, several essential parameters of a well cannot be determined without knowing the rates at which the different fluids are pumped into or out of the formation: A bottom hole pressure (BHP) calculation requires knowledge of the fluid velocity to account for friction losses. This applies to cementing, stimulation as well as drilling operations. The cumulative volumes pumped in a formation are estimated by integrating the flowrate over time. This is of prime importance especially in stimulation or in cementing when flushing the tubing or the casing. Flow regime control based on flowrate and viscosity monitoring is essential for achieving a good mud removal in cementing operations. The use of two universal flowmeters, one on the treating line and the other on the return line, allows the detection of economically undesired fluid P. 577^
- North America (0.28)
- Europe > Norway > Norwegian Sea (0.24)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the EAGE Annual Conference & Exhibition incorporating SPE Europec held in Copenhagen, Denmark, 4-7 June 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract In-well flow measurement remains as one of the most difficult tasks in the oil and gas industry, mainly due to the challenging conditions of the downhole environment. When made successfully, however, it plays a major role in monitoring and optimizing well performance, especially for the wells equipped with advanced completion devices. The increasing demand for in-well flow measurement is also driven by other factors including zonal production allocation in multizone completions as well as reliable commingled production, reduction of surface well tests and facilities, and detection of production anomalies. This paper provides a closer look at one of the state-of-art in-well flow measurement technologies: optical, strain-based, phase flow rate measurements via turbulent structure velocity and sound speed of the turbulent flow. It is an introduction to how this flow measurement technology works and how it is applied to different flow applications from single-phase injectors to multiphase producers. Specific field examples representing different flow applications are also referenced to published material. The strong and weak points of the technology are explored, and in the process, an operation envelope is produced for the use of this technology. The system response to the presence of advanced completion devices are also discussed, guidelines are given, and recommendations are made based on field and lab tests. Understanding a technology's strong and weak points before implementation is essential to ensuring that informed and successful decisions can be made concerning its use for a given application. This process is often mutually beneficial to both operators and equipment manufacturers since collaborations can lead to advancement of technology and, as a result, provide even more reliable solutions. Background The use of the phrase "intelligent well" was not common a decade ago. The reason is hidden in its definition.
- North America > United States > Texas (1.00)
- Asia > Middle East (1.00)
- Europe > United Kingdom (0.68)
- Europe > Denmark > Capital Region > Copenhagen (0.24)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Ship Shoal South Addition > Block 359 > Mahogany Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Ship Shoal South Addition > Block 349 > Mahogany Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Peterhead Graben > P.986 > Blocks 19/10 > Buzzard Field > Kimmeridge Formation > Buzzard Sandstone (0.99)
- (10 more...)
Abstract Performance of a new three-phase (3-P) flow measurement system is presented using multiphase flow loop data. The system consists of two currently available products: an optics-based flowmeter and a near-infrared (NIR) water-cut meter. The measurement capability and performance of a combined system comprising two robust and field-proven technologies under realistic flow conditions is demonstrated for the first time. The new 3-P flow measurement system represents a viable alternative for subsea multiphase flow measurement and can also be used on offshore platforms, onshore as well as downhole, in single-zone or multizone applications. The flowmeter system relies on three main measurements: bulk velocity and sound speed measured by the optics-based flowmeter, and water-cut measured by the water-cut meter. The velocity measurement is a robust measurement based on turbulent flow and is not affected by upstream flow conditions. The water-cut measurement is based on NIR absorption of water and oil molecules, and therefore, is immune to water salinity and the presence of gas (such as free gas, gas in solution, and oil foaming). Total flow rate is calculated using the bulk velocity measurement; liquid holdup and density of the mixture are obtained by introducing the mixture sound speed and the water-cut measurements into a flow model. The results of the multiphase flow loop test demonstrated that the new flow measurement system is capable of resolving total volumetric flow rates as well as phase volumetric flow rates in a broad gas-volume-fraction (GVF) band. Furthermore, mixture density can be successfully calculated from the flow model and, as a result, the mass flow rates can also be determined. The test data also confirm that the water-cut measurement is not affected by foaming issues and associated density variations. The test results are discussed in detail in the paper. The new flow measurement system offers several advantages. The flowmeter can be installed in any orientation and does not require recalibration. Its nonintrusive and fullbore features mean no permanent pressure loss, and high resilience to erosion and corrosion. The nonnuclear water-cut meter measures water cut in the broad GVF spectrum and is not affected by challenging flow conditions, such as slug flow. Installed inside a wellbore, an optics-based flowmeter can provide reliable flow measurement for the life of that well with no significant drift in signal.
- Asia > Middle East (1.00)
- Europe (0.95)
- North America > United States > Texas (0.70)
- North America > United States > Colorado > Piceance Basin > Buzzard Field > Mesaverde Formation > Williams Fork Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Buzzard Field > Mancos Formation > Williams Fork Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Buzzard Field > Iles Formation > Williams Fork Formation (0.99)
- (3 more...)
Abstract Over the years, especially in brown field operations, injected lift gas metering has remained a concern among operators. In some legacy fields, there is little or no functional gas injection metering in place. A whole lot of challenges ranging from obsolete field metering equipments, OPEX, meter calibration and maintenance challenges, etc, has impacted optimization opportunities from gas lifted wells. At other times, it has been difficult to justify facilities expenditures for late-life, gas lifted wells. Operators must therefore balance the benefits of maximizing liquid production from a gas-lifted field versus recycling the lift gas and constraining the pipeline network capacity. An important input for gas lift optimization is the volumetric flow rate of injection gas. This data can help experienced Well analysts and gas lift technicians determine if the lift gas injection into the well is optimal in line with advised lift gas rates from models, thus providing directional guidance on what change(s) should be made to improve a well's performance. The volumetric flow rate can be used to estimate the transit time of injected gas, which can then be combined with other tools to determine downhole injection points. In the Badan field, onshore Niger Delta, with ageing gas lift infrastructure, changes in production rates and fluid properties, there is a need to ensure that real-time lift gas measurements are obtained which allows Production engineers update their flow assurance models and validate new plans. A portable, non-intrusive, ultrasonic flowmeter would be ideal for obtaining the injected gas flow rate in these situations. Clamp-on meters have been around for over 30 years. As a result of improvements in flow metering technology, the last decade has seen clamp-on flowmeters working on a full range of gas applications. Many non-fiscal applications that were done by traditional flowmetering spools are now shifting to clamp-on meters. These meters are cost effective, easy to install, and are proven to be very reliable and accurate. These meters can also be used to monitor gas-lift injection rates during production testing operations to establish a set point for gas lift and achieve maximum hydrocarbon liquid production rates. In this paper, the results of a pilot trial on the use of a portable clamp-on ultrasonic flowmeter for Gas lift operations/optimization in the Badan field is discussed. Results from optimization efforts in the field has seen a net increase of +/-10% of liquids on a well-by-well basis, which could equal about $200,000 per well per year. A further benefit also includes a reduction in lift gas, which increases capacity within the production piping for additional produced liquids and associated gas. This can greatly impact the bottom-line in a lower-for-longer price environment.
- North America > United States > Texas (0.86)
- Africa > Nigeria (0.67)
Diverting-spinner flowmeters are the most accurate of the spinner devices when low total rates and multiphase flows occur. The stream is diverted through the tool's barrel, thereby raising the velocity of flow and increasing the sensitivity to the point that diverting spinners can detect rates as low as 10 to 15 B/D. Because of the limited clearance between the spinner and the barrel, this velocity is enough to overcome friction and turn the spinner. Furthermore, a flow of 100 B/D passes through the barrel at 34 ft/min, which is sufficient to start the homogenization of the flow, which eventually eliminates phase influence. In casing, a rate of 2,000 B/D is needed to have the same effect around acontinuous spinner.
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)