Multiphase Flow Measurement Using Tracer Technology at Dulang Oil Field, Malaysia

Bohari, M Ali M; Leeuw, Hendrik de; Nilsson, Carl-Oskar

doi:10.2118/80501-ms

Cited by 3 publications

(1 citation statement)

References 1 publication

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“…A second reference available for net oil rate is the multiphase tracer technique 3 . The X Field production station 3-phase low pressure test separator, named TSEP-B in this paper, was used for that purpose.…”

Section: Introductionmentioning

confidence: 99%

Reliability of Multiphase Flowmeters and Test Separators at High Water Cut

Ojukwu¹,

Edwards

2008

SPE Western Regional and Pacific Section AAPG Joint Meeting

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The use of multiphase flowmeters (MPFM) for well test measurements is increasingly becoming a standard practice replacing conventional test separators. These MPFMs are usually tested and calibrated in laboratory controlled flow loops using idealized fluids in steady state conditions. However for high water-cut, high gas-volume-fraction and low pressure unstable flow these controlled conditions are far from reality which can lead to unforeseen errors in the field. Recent experience shows that in certain conditions, the various types of multiphase flowmeters react quite differently to the measurement challenges of transient flows in high water cut and high gas volume fractions (GVF). Some meters can be unreliable in measuring oil rates in certain conditions which leads to inaccurate estimation of the wells' potential and associated uncertainty in plans for production optimization. For example the inaccuracies in measured oil rates could be greater than the gain expected from a stimulation or restoration. An inaccurate measure of oil rate also leads to a poor reconciliation factor and poor estimation of reserves. By resolving these inaccuracies and allocating oil correctly to wells it is possible to invest in right opportunities thereby saving unnecessary expenditure. The factors that affect multiphase flowmeter measurement can range from excessive gas-volume-fraction, low line pressures, solids and unsteady flow.In 2007 an in-situ comparison was made of two types of multiphase flow meters and two separators to determine the most appropriate well test device for X Field in the Sultanate of Oman. X Field wells are artificially lifted and have a high water cut of 80%. The reconciliation factor (also known as the back allocation factor) before this well test campaign was 0.54. The comparison was made on twelve wells producing to X Field station. Each well was tested for 12 hours in series using an existing inline MPFM, a low pressure production test separator, a second mobile MPFM, a 1440psi separator, and a multiphase tracer technique. The objective to determine the most reliable technique(s) of measuring oil production rates was accomplished, and now the reconciliation factor is 1.03. This paper describes the comparison, how the results were analyzed, and the comparative error associated with each technique.

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Section: Introductionmentioning

confidence: 99%

Reliability of Multiphase Flowmeters and Test Separators at High Water Cut

Ojukwu¹,

Edwards

2008

SPE Western Regional and Pacific Section AAPG Joint Meeting

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Operational Experience of Wet Gas Metering in Malaysia

Leeuw

Dybdahl

Nilsson

et al. 2004

SPE Asia Pacific Oil and Gas Conference and Exhibition

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Wet gas metering technology was chosen by ExxonMobil for continuous well testing and advanced production measurement at two satellite platforms located in the South China Sea offshore Malaysia. The satellite facilities are equipped with permanently installed SmartVent wet gas venturi based meters at each well location. Special wet gas flow calculation and monitoring software have been developed and installed on a separate flow computer installation interfaced to the host platform DCS system. Prior to installation the wet gas meters have been subjected to full scale testing at a representative high pressure gas/liquid flow test facility. This has resulted in valuable measurement experience and a unique set of experimental wet gas data. After start up of the field on-site verification/calibration will be performed using the tracer technology method. As of today valuable results have been obtained from the system. The present application is a demonstration that wet gas flow measurement is increasingly gaining acceptance in replacing expensive well test separators and related infrastructure in gas/condensate field developments. Besides the significant cost savings, the availability of continuous readings of each well's production rates allows for enhanced reservoir management and production optimisation. At the same time experience has shown that successful implementation of wet gas flow measurement requires adequate attention to every aspect of the metering process. Introduction Significant cost savings related to production testing of gas/condensate wells can be realised if conventional test separators and related infrastructure are replaced by SmartVent wet gas venturi based flow meters in each well flow line, and the wetness of the flow is verified/calibrated using the non-radioactive MultiTrace tracer technique[1,2,3,4]. Accurate wellstream PVT samples can be obtained in combination with the tracer samples for EoS flash calculations and process simulation. The corrected gas flow rate can be verified via the use of the MultiTrace gas tracer technique. Prior to their installation (figure 1a and 1b) the wet gas flow meters have been subjected to full scale testing at a high pressure natural gas/condensate test facility in Norway. The first objective was to calibrate all the 15 meters in single phase flow in order to establish the actual discharge coefficients and wet gas parameters. The second objective was to test 3 out of the 4", and 3 out of the 6" meters under hydrocarbon wet gas flow conditions in order to evaluate the used wet gas measurement correlations for determining the actual gas and total liquid flow rate[1,5,6]. The tests were performed at pressures of around 35 bar and 65 bar, at different gas velocities, and with liquid fractions up to around 4–5% by volume. The latter corresponding to a Lockhart-Martinelli parameter of up to approximately 0.125. The experiments were conducted using hydrocarbon natural gas and condensate. Wet Gas Metering Principle The selected wet gas metering system consists of the installation of SmartVent wet gas venturi based flow meters at each individual wellhead providing the continuous measurement of the gas and total liquid flow rate (figure 2). The measured liquid phase will initially be split into water and condensate fractions via the use of established fluid property data and EoS flash calculations. After start-up of the field the tracer technology method will be used to measure the water and condensate flow rates independently. The wet gas flow calculations, as schematically shown in figure 2, are based on the well known De Leeuw gas correction correlation for the correction of the gas flow rate due to the free liquid content, and an additional correlation for determining the total liquid flow rate. Both correlations do not rely on homogeneous flow conditions, nor do they require the flow to be conditioned in any other way. No obstructions are placed inside the flow line other than the wet gas venturi based meter.

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Experimental Research on Oil–Water Flow Imaging in Near-Horizontal Well Using Single-Probe Multi-Position Measurement Fluid Imager

2022

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To obtain local flow velocity and holdup for oil–water in a near-horizontal well, array probes were adopted in the cross section of the wellbore. In this study, a fluid flow imaging logging tool called the single-probe multi-position measurement fluid imager (SPFI) was developed, which consisted of only a single turbine flowmeter and a single capacitance holdup probe. Most importantly, it could collect local velocity and holdup information at different locations along the vertical direction of the wellbore diameter. Firstly, in the large-diameter multi-phase flow simulation test loop, the instrument was placed at five different positions along the wellbore cross section to perform simulated measurements in different wellbore deviation angles and oil–water flowrates. Secondly, the experiment data was analyzed, and the experiment flow pattern chart, instrument response coefficient, and rule of the instrument response were obtained. At the same time, the calculation methods of local holdup and local velocity were derived. Thirdly, by combining the interpolation algorithm, velocity imaging and holdup imaging were implemented, and the stratified flow model was used to calculate the flowrate of each phase. Finally, this study provides technology support for production profile data interpretation using the fluid flow imaging tool for oil–water in a near-horizontal well.

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Multiphase Flow Measurement Using Tracer Technology at Dulang Oil Field, Malaysia

Cited by 3 publications

References 1 publication

Reliability of Multiphase Flowmeters and Test Separators at High Water Cut

Reliability of Multiphase Flowmeters and Test Separators at High Water Cut

Operational Experience of Wet Gas Metering in Malaysia

Experimental Research on Oil–Water Flow Imaging in Near-Horizontal Well Using Single-Probe Multi-Position Measurement Fluid Imager

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