SPE

Continuous and fullbore spinner flowmeters

PetrowikiJuly, 2015

There is no generic difference between a "continuous" spinner and a "fullbore" spinner. In the case of the fullbore, the spinner element folds into a diameter no greater than that of the tool when in the tubing, but expands into a larger diameter for surveying in the casing. The continuous spinner does not have this capability. The difference between the two is too small to justify a separate discussion of each. The continuous meter derives its name from the need to move the tool fast enough to overcome frictional torque and start the spinner element rotating. It also derives its name from the in-situ calibration procedure that uses logging runs at several different cable speeds with the well shut-in at the surface. Neither continuous nor fullbore, however, can provide a log that is quantitative whenever the fluid velocity is sporadic, that is, changing in the logged interval. The continuous and fullbore tools share three features: * First, the spinner element on each is at the very bottom of the tool string. If the temperature tool is run in combination with the spinner, then the thermometer's sensor will usually be located in the tool string above the spinner.

Petrowiki

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines: Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)

Technology:

Information Technology > Knowledge Management (0.40)
Information Technology > Communications > Collaboration (0.40)

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A New Flowmeter for Production Logging and Well Testing

Piers, G.E. (Schlumberger Well Services) | Perkins, J. (Schlumberger Well Services) | Escott, D. (Schlumberger Well Services)

OnePetroSeptember, 1987

Abstract There are two primary reasons to utilize a flowmeter. One reason is to measure total flow rate at different depths in a well. Total flow is then used for a single phase flow profile or used in conjunction with other sensors to produce a multiphase flow profile. Measurement of transient rate in conjunction with pressure transient testing is another use of the flowmeter. The analysis of these transients then yields reservoir parameters such as permeability, skin, and reservoir pressure. In either case, flow rates must be accurately measured or gross errors in the final interpretation will result. Multiphase flow, especially in deviated wells, often results in an unpredictable flowmeter response. Most wells are multiphase downhole with a high percent of water present even though little or no water is being produced at the surface. This downhole condition makes it difficult to derive an accurate flow rate from a measured spinner speed. Petal basket flowmeters attempt to force fluids into a flow regime that can be measured but fail because all of the flow is not diverted through the metering section. A new flowmeter is described that has a linear, predictable response in single and multiphase flow and results in a much better measurement of downhole flow rates. Flow loop data are presented, comparisons are made of the new flowmeter response with other flowmeter responses and the results of field tests are discussed. Introduction Fluid flow is a complex phenomenon. There are many correlations and models attempting to describe multiphase flow and account for phase velocities, pressure gradients, and flow regimes. Brown and Beggs discusses the methods of several authors in their chapter on "Multiphase Flow in Pipes" as do Hasan and Kabir in their study of flow behavior in vertical wells. Even wells that produce essentially water free at the surface usually have a high water holdup (fraction of water by volume) downhole below tubing. This high water holdup occurs because the velocity of the produced fluids downhole, in normally used casing sizes, is not sufficient to clean water out of the well (less than 1% of the wells in North America produce enough to be monophasic downhole). The multiphase environment can cause anomolous flowmeter readings, a problem that is particularly aggravated in deviated wells. In transient well testing using transient rate and pressure measurements the holdups and velocity profiles are often changing with time. The effect on flowmeters can negatively affect the estimation of reservoir parameters. Flowmeter readings in monophasic wells are also affected by changing velocity profiles. A new device, an inflatable diverter flowmeter tool, has been developed to force the fluids into a flow regime and/or velocity profile that will enable fluid velocity (flow rate) to be measured. SINGLE AND MULTIPHASE FLUID FLOW Fig. 1 shows velocity profiles for laminar and turbulent flow of a single phase fluid. The center velocity for laminar flow may be twice that of the average fluid velocity. Many flowmeter measurements are not only a function of the velocity profile, but are also a function of tool size relative to flowing cross-sectional area, tool centralization, and tool hardware effects on the velocity profile. However, most wells are not single phase downhole. It takes approximately 1000 STB/D of oil or 1,000,000 to 2,000,000 scf/of gas to carry produced water or completion fluids out of 5.5-in. casing or to produce a relatively homogeneous mixture of fluids. The exact number depends on formation volume factors. In most producing wells there is a very high percentage of water present over much, if not all, of the producing interval. This condition occurs even if little or no water is produced at the surface and results in flow regimes such as shown in Fig. 2, or similar regimes representing 3-phase flow. Because of the difference in flowing fluid properties (mainly density, viscosity and interfacial tension), the fluids move at different velocities. The flow regime at a given time is not only dependent on flow rates, but also on fluid properties, pipe size and condition, wellbore deviation, logging tool presence, and proximity of fluid entries. Under these circumstances, it is understood that some flowmeters may not be able to obtain an average fluid velocity. P. 703^

OnePetro

doi: 10.2118/16819-MS

SPE

SPE-16819-MS

SPE Annual Technical Conference and Exhibition

Country:

North America > United States > Texas (0.47)
North America > United States > California (0.29)

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines:

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The Full Bore Flowmeter

Leach, B.C. (Schlumberger Well Services) | Jameson, J.B. (Schlumberger Well Services) | Smolen, J.J. (Schlumberger Well Services) | Nicolas, Y. (Etudes et Production Schlumberger)

OnePetroOctober, 1974

Leach, B.C., Member SPE-AIME, Schlumberger Well Services, Houston, Texas Jameson, J.B., Member SPE-AIME, Schlumberger Well Services, Denver, Colorado Smolen, J.J., Member SPE-AIME, Schlumberger Well Services, Houston, Texas Nicolas, Y., Etudes et Production Schlumberger, Clamart, France American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. This paper was prepared for the 49th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Texas, Oct. 6–9, 1974. Permission to copy is restricted to an abstract of not more than 300 words. illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract The Fall Bore Flowmeter is a spinner-type velocimeter designed to be lowered through production tubing in order to measure flow rates in the casing below. The tool provides continuous fluid-velocity measurements at lower production rates than was possible with earlier Continuous Flowmeter equipment. possible with earlier Continuous Flowmeter equipment. In polyphasic flow it provides measurements that are more accurate and less affected by fluid-viscosity changes than those from the earlier Continuous Flowmeter. The tool has a 1 11/16-in. diameter. The spinner-and-protective-cage assembly is run in the hole while collapsed to the 1 11/16-in. size. When the tool is below the tubing, it opens and the spinner blades are exposed to a large cross section of the flow in the casing. A considerably larger position of the total well production is metered through the spinner section production is metered through the spinner section than with the Continuous Flowmeter tool. The fullbore exposure of the spinner increases its sensitivity for use in low flow rates, and decreases the effect of changes in viscosity in polyphasic flow. The spinner suspension system has been designed to minimize the effects of friction. The tool is collapsed as it is pulled back into the tubing, and is held in the collapsed position while being retrieved to the surface. position while being retrieved to the surface. The Full Bore Flowmeter may be run by itself or in combination with the Gradiomanometer, Thermometer, Manometer, and thru-tubing Caliper. A Casing-Collar Locator run in combination with the Flowmeter provides positive depth control. provides positive depth control. Several field examples are presented showing downhole flow profiles and production profiles where problems exist, such as crossflow, plugged perforations, problems exist, such as crossflow, plugged perforations, and changes in contributions to production.

OnePetro

doi: 10.2118/5089-MS

SPE

SPE-5089-MS

Fall Meeting of the Society of Petroleum Engineers of AIME

Country: North America > United States > Texas > Harris County > Houston (0.94)

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines:

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Inflatable Diverter Flowmeter

Piers, G. Ed (Schlumberger)

OnePetroJune, 1989

ABSTRACT Most wells are multiphase downhole with a very high percent of water present (water holdup, Yw) even though very little or no water is being produced at the surface. This happens because fluid velocities are too low to carry the water to the surface. Consequently, it can be very difficult to obtain a total flow rate from most spinner flowmeters. Another complicating factor is wellbore deviation from vertical which causes gravity segregation of fluids and further degradation of spinner response. There is usually a great degree of uncertainty as to what velocity profile or flow regime a flowmeter is in, thus making it difficult to interpret a flowmeter response, even if a response model exists. Petal basket flowmeters attempt to get around these problems by forcing fluids into a regime that can be measured. They quite often fail because they do not divert all of the flow through the metering section. This leakage around and through the basket happens in a very unpredictable fashion and results in a nonlinear spinner response that is also a function of the relative proportion of fluid types flowing through it. The Inflatable Diverter Flowmeter (IDF*) is a relatively new flowmeter for use in measuring flow rates versus depth or time up to 3500 B/D. It is very much less affected by the conditions mentioned above. The flowmeter was run in several flow loops to acquire data necessary to model its response. Conditions covered were liquid-liquid flow, gas-liquid flow, and dry gas flow. Data were gathered at vertical and various degrees of inclination. Liquid viscosity for one case was varied up to 200 cp.

OnePetro

SPWLA

SPWLA-1989-CC

SPWLA 30th Annual Logging Symposium

continuous flowmeter, DEGF, Diverter Flowmeter, flow metering, flowmeter, full bore flowmeter, inflatable diverter flowmeter, inflatable diverter flowmeter response, layer 1, layer 2, layer 3, Log Example, production control, production logging, production monitoring, PTEM, Reservoir Surveillance, spwla thirtieth annual logging symposium, Upstream Oil & Gas

Industry: Energy > Oil & Gas > Upstream (1.00)

SPE Disciplines:

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High-Pressure Universal Volume Flowmeter for Cementing, Stimulation, Drilling, and Production

Codazzi, D. (Dowell Schlumberger) | Mioque, J.L. (Dowell Schlumberger) | Moncharmont, J.A. (Dowell Schlumberger) | Montaron, B. (Dowell Schlumberger)

OnePetroSeptember, 1987

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^

OnePetro

doi: 10.2118/16650-MS

SPE

SPE-16650-MS

SPE Annual Technical Conference and Exhibition