SPE 118148

Extending the Range of Multiphase Metering to Challenging High Water Cut Gas-Lifted Wells: TOTAL ABK Field Application David Costa; Total ABK, Jean-Paul Couput, Total; Florian Hollaender, Bruno Pinguet and Thomas Koshy; Schlumberger

Copyright 2008, Society of Petroleum Engineers This paper was prepared for presentation at the 2008 Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 3–6 November 2008. 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 Flow metering using conventional separation-based technologies in low-pressure high gas rate environments typical of gas-lifted wells is a very difficult operation. Owing to low retention times of the gas, the quality of separation and existing instrumentation is often doubtful leading to an under-estimate of liquid rates. An aggravating factor is that such wells are often producing at high water-cuts, thus leading to significant uncertainty on oil rates.

To solve such metering challenges with a large majority of their wells operating above 95% gas fraction under metering conditions and water cuts often higher than 90 %, TOTAL ABK has evaluated different well testing & monitoring strategies based on multiphase metering use.

A compact dual-energy gamma-ray Venturi multiphase flow meter (MPFM) was selected and placed under field trial to assess whether this technology could reduce the uncertainty on oil production by removing any impact of imperfect separation. 20 tests were performed considering 15 wells over a period of 10 days to assess MPFM performance and repeatability in a wide range of conditions.

In most cases, it was found that the meter’s performance compares favorably with that of the test separator located in line. Furthermore, the high-frequency high-resolution output of the meter allowed the operator to assess well efficiency and stability and to understand the behavior of the gas lift system. It was shown that such wells have a tendency to behave erratically at very high frequency, leading to fast and significant variations of the well productivity that could not be captured by conventional means and could potentially lead to erroneous results as well as sub-optimal well performance.

The field test proves that the multiphase metering solution used in this trial can be used successfully and is presenting a reliable alternative or complement to conventional test separators for flow metering in low-pressure high water cut wells under gas lift, providing operational flexibility and additional information of interest to optimize well productivity. Introduction: Field and Wells Description, Monitoring Testing Needs In 1972, a year after the creation of the UAE Federation, Total was granted a concession to develop the Abu Al Bukhoosh field. At that time, the reserves to be produced were estimated at 194 MMstbo, the field having an expected life span of 15 to 20 years.

Today, after 36 years and a cumulative production of 510 MMstbo, oil is still being produced and will continue to be for many years to come (Fig. 1).

In order to achieve such a result, extensive, continuous efforts have been deployed over the years to further develop Abu Al Bukhoosh resources, in response to the growing maturity of the field. A remarkably wide variety of means and techniques have been deployed throughout its development to curb the decline in production and extend its life, such as phased development, secondary reservoirs development, well activation, optimization of production mechanisms, use of emerging technologies, understanding heterogeneities and replacement and upgrading of equipment.

The Abu Al Bukhoosh oil field is located 80 km offshore Abu Dhabi. It is a large NE-SW anticline, affected by NW-SE trending faults, which straddles the border between the United Arab Emirates and Iran.

Currently on Total ABK field, well testing of around 65 oil producers is performed on two test separators. Total ABK

wishes to improve the accuracy of testing its production wells by using a multi-phase flowmeter which will allow to increase the number of well tests and better characterize/follow-up wells instabilities leading to optimized production.

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Challenges Well flow conditions

In TABK field , operations have to deal with a large number of production wells with very high Gas Volume Fractions ( GVF ) & Water Liquid Ratio ( WLR ) and large ranges of gas & liquid flow rates. For instance , liquids can range from 30bbl/d to7000bbl/d with large instabilities in some wells. Well oil production are ranging from less than 6bbl/d to 1750 bbl/d

An additional challenge is related to the behavior of flows and flow patterns which are quite different from one well top the other mainly due to well stabilization it self but also to instability and slugs generated by flow line .

Production test separator

Well test is currently performed using two 3 phases test separators, 1 installed on central platform and the other on a remote platform . They use conventional instrumentation i.e. orifice plates at the gas outlet & turbine meters for oil & water.

On the principle, the measuring technology in place is suitable & accurate but some limitations have been noticed such as difficulties experienced when testing low liquid producers & slugging wells. High instabilities are also generated by the separator control & valve system with associated measuring limitations due to large turndown flow rates and quick variations to monitor.

Another drawback of the existing well testing solution is the test duration which could prevent testing all the wells on a regular basis and the difficulty to test wells which are far away from the test separator. Due to network configuration, test separator preparation and pipe line stabilization could require a significant amount of time before having wells stabilized (8 hours) and ready to be tested.

All the previous points could result in non representative well tests data and incorrect flow rate estimation of production wells with wrong back allocation to wells

Multiphase metering solutions to improve well testing & monitoring

A strong emphasis has then been put by affiliate management to find out ways of improvement and multiphase metering systems have been identified as a solution to complement existing solutions with the capability to test well and provide production well data on a more regular basis

TOTAL has a significant number of MPFM in operation and has experiences both with in line MPFM and partial separation MPFM systems ( J-P Couput 2001 ) . In line MPFM have been applied to gas lifted wells follow up involving high gas volume fraction (GVF) at GVF higher than 95 %. The flow rate results closely matched the separator data and provided valuable information related to multiphase flow dynamics and well behavior.

High-resolution MPFM technology made possible to study slugging in wells where gas slugs were pushing liquid pockets to surface. It was possible to determine the periodicity of liquid and gas slugs (<1 hr) with a resolution of less than 1 min and to evaluate oil production per slug.

In line Vx MPFM solution

Several MPFM options both in line or with partial separation have been studied and compared. Various technical studies have been performed with Total headquarters on different fixed multiphase flowmeter applicable to Total ABK production conditions.

For very high GVF applications, tests have been performed in the past with cyclonic separator based MPFM . Such technology was found to be difficult to operate and control with ABK sluggish wells and installation on unmanned situations was questionable. Based on that, it has been proposed to use systems as simple as possible with minimum limitations on instrumentation.

Choice has been orientated to compact in line MPFM in order to meet operational requirements such as: • Installation & operation simplicity • Minimum maintenance • Reliability and robustness to flow instability • Capability to be used on satellites platforms in unmanned situations • Service supply

The main drivers to consider Vx MPFM technology from Schlumberger are the suitability to the wide range of wells and

flowing conditions, and the Vx MPFM compliance with Total ABK applications, due to track record, equipment robustness, tolerance to transitory flows, overall reliability (field proven technology) and compliance with operational constraints.

Compared to the highly complex separation based MPFM system, the compact Vx MPFM is a well proven system which will work up to 96% with some possibility to be used at GVF up to 98%. In that prospect, it was considered as able to provide valuable information for 75 % of wells.

A series of on site tests were performed from 23 April 2007 to 3 May 2007 to assess the metrological and monitoring

performances of Schlumberger Vx multiphase flowmeter in the specific conditions of ABK wells.

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MPFM Trial Technology Description

Calculation workflow The technology used during those trials consists of a meter providing collocated total rate and fraction measurements. The

MPFM uses a Venturi spool equipped with a differential pressure recorder for rate determination and a single low-activity gamma-ray source and multi-energy gamma-ray detector for fractions determination. For the purpose of dynamic fluid properties determination, flowline pressure is measured at the throat of the Venturi spool and flowline temperature at a blind-T flow conditioner, where mixing ensures the most representative measurement. A schematic of the MPFM assembly is presented in Fig. 2. A comprehensive overview of the technology can be found in Theuveny et al. (2001) and references therein, however, in order to provide the right basis for a comprehensive understanding of the challenges encountered, the relevant points will be highlighted in the following.

The flow-rate calculation workflow can be expressed in 3 simple steps: 1. First the flowing fractions are determined from the multi-energy gamma-ray attenuation measurements,. 2. Second, using the differential pressure measurement between the inlet of the Venturi section and its throat the

total flow rate is calculated from a Venturi equation. This total rate is then split into its 3 components: oil rate, water rate and gas rate at metering conditions.

3. Finally, the flow rates at operating (line) conditions are converted to standard condition rates accounting for volumetric changes (oil and water shrinkage, gas expansion) and for phase changes (gas coming out of liquid phases, possibly condensate dropping out of the gas phase)

Those calculations are performed at a frequency of 45Hz, or every 22ms in order to capture the dynamic behavior of flow,

which has a major impact in the application targeted here as will be shown later. Of those three steps, the critical one in a low-pressure, high water-cut, high GVF environment is that consisting in

determining the flowing fractions. Venturi calculations are extremely robust in themselves and the determination of fluid properties required for flow-rate calculations (fluid densities at line conditions, conversion factors from line to standard conditions) is fairly straightforward to determine from atmospheric measurements within the required accuracy in this environment. As an example to the latter point, it can be clearly understood, for instance, that oil and water shrinkage will be small and unlikely to be affected by any significant error. Similarly, gas volumes released from the oil and water phases from metering to standard conditions will have little impact on the total gas rate, largely dominated by the large gas fraction present at metering conditions.

Fractions determination The physical principle behind the fraction measurement is that of gamma-ray attenuations. When sending a beam of

gamma-rays though any matter, be it in liquid phase, gas phase or even under solid state, some of the energy will be absorbed by the matter via collisions. The actual physical phenomenon causing this loss of counts (number of gamma-rays per unit of time) depends on the type of gamma-rays, characterized by their energy level.

These effects have two interesting characteristics: • First they represent interactions between gamma-rays and individual atoms (in fact electrons) and thus are not

affected by the structure of phase, be it water-continuous, oil continuous or emulsified for instance. • Second, as different energy levels are affected in different ways depending on the type of fluids, the use of two

different energy levels, one dominated by photoelectric absorption the other being also affected by Compton scattering (the Barium-133 isotope used generates gamma-rays at two main energy levels) provides a good differentiation between the 3 phases. In addition, the Barium isotope also emits gamma-rays at a higher energy level of approximately 356 keV. While not used in the standard rate calculations, this third type of gamma-rays can be used for data quality control or more advanced applications (Pinguet (2006), Poyet (2002)).

Mathematically, the attenuation can be expressed as follows for a given matter and energy level:

ADeNN ρ−=

0 Equation 1

where N represents the number of gamma-rays exiting the matter per interval of time, N0 those entering the matter, D the gamma-ray path length (diameter of the Venturi throat), ρ the density of the matter and A the mass attenuation of the matter at the energy level considered. Important to note, the mass attenuation A is only a function of fluid composition, in other words water would have the same mass attenuation response whether in liquid phase, as ice or considering steam.

A simplified way to express how different fluids react to different energy levels is to say that the high energy gamma-ray

attenuation is mainly affected by the density of the fluids while, the low energy attenuation is a function both of the fluid density and of the type of molecules.

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When dealing with a water-oil-gas mixture, Eq. 1 becomes:

[ ]HELEggg

HELEooo

HELEwww AAAD

HELE

eNN ,,,

,

0

ραραρα ++−=⎟⎟⎠

⎞⎜⎜⎝

⎛ Equation 2

where α represents the volumetric fraction (holdup), subscripts w, o and g represent water, oil and gas respectively and superscripts LE and HE represent low energy and high energy respectively. With two attenuation measurements and knowing that the sum of the fractions of water, oil and gas equals 1 (100% of the pipe being occupied by those fluids phases), we have a system of three independent equations that can be solved for the three fractions.

For convenience, instead of using independently densities and mass attenuations, the linear attenuation ρ.A is often used. Using the linear attenuation, it is possible to use a graphical representation of the nuclear attenuation triangle. Representing the low energy linear attenuation of each pure phase on the x-axis and the high energy linear attenuation on the y-axis creates, as in Fig. 3, a triangle whose apexes represent the nuclear attenuation response of pure phases. Any mixture of those three phases will yield a measurement located within that triangle and the location of the measurement will be a direct indicator of flowing fractions: the closer the operating point is from the gas point the higher the gas fraction. Similarly, the closer it is from the gas-water line, the higher the WLR.

Field Test Setup

In order to assess the suitability of the selected MPFM technology to test wells operated by Total ABK, it was essential to consider a wide range of conditions representative of the field operating conditions, but also to take into account the limitations of the technology. For instance, it was to be expected that when operating at extremely high GVF or at very low rates it would be very challenging to attain representative results. Furthermore, it was important to have some reference to validate the results. A test separator located on the central platform was selected as comparison point and the MPFM was installed directly upstream of that separator to ensure that operating pressure and temperature conditions would be similar. Wells from remote platforms were tested at the central station via a dedicated test line, in cases several kilometers long.

An initial list of 27 wells was considered as candidates for testing. Based on historical data the suitability of each well as a candidate for testing was determined considering two main criteria: expected gas volume fraction and differential pressure across the Venturi section. For the first point, extremely high GVF values (above 98%) are known to provide a challenging environment for accurate liquid flow rates measurements, essentially because the liquids represent a very small fraction of the flow stream. Therefore, cases below 98% were considered as primary targets, while in order to try to stretch the operating envelope of the meter cases between 98 and 98.5% GVF were considered as secondary targets. The differential pressure sensor used in the MPFM has a calibrated range of operation from 50 to 5000mbar, providing a turndown ratio of 10:1 at constant operating conditions. This led to discarding some low producers or very high producers falling outside of that range. The most adequate size of meter was found to be that considering a 52mm throat size (2.05” throat diameter, 4.1” inlet size).

Based on this suitability study, each well was assigned a suitability index, graphically represented on Fig. 4 along with the wells finally selected for testing. 10 wells were selected as initial targets with 5 additional wells selected to further extend the quality of the evaluation by pushing the meter beyond its accepted operating range. In total, 15 wells were tested through 20 separated tests designed to assess measurement repeatability as well as to perform sensitivity studies on the gas lift injection rates or choke setting.

In order to prepare for operations, and specifically to set up the attenuation and fluid properties references, atmospheric

liquid samples (oil and water) were gathered from each well to be tested before the start of operations. This allowed for the determination of a fluid properties model as well as the measurement of attenuation references. In parallel, gas composition was obtained from gas lift analysis reports and were used to set up the properties of the gas.

All calculation inputs were determined prior to the start of testing. It would have been possible, however, to determine those inputs during the tests and updating them a posteriori. All measurements acquired (pressure, temperature, differential pressure, gamma-ray counts) are absolute measurements that do not rely on a representative input of fluid properties before the start of acquisition. Acquired data can be re-processed after the operations, using corrected inputs based on, for instance, fluid properties measured during or after MPFM data acquisition. Review of Test Conditions and Challenges

A total of 15 wells were tested over 20 distinct tests spanning 10 days of operations. Two wells were tested twice to assess the repeatability of the measurement and 5 tests were conducted with variable production settings, be there variable flowing wellhead pressures or variable gas lift injection rates. The typical test duration was between 8 and 10 hours per test, with some longer ones generally when looking at well stability issues after changing the production settings.

The MPFM tool used was exposed to flow-rates between approximately 150 stb/d and 5,900 stb/d of liquid, and between 0.7 MMscf/d and 6.2 MMscf/d of gas. Flowing pressures were between 8.6barg and 12barg, with temperatures from 25 degC up to 80 degC. Calculated gas volume fractions ranged from 86% up to 99% during variable-condition tests and water cuts from just over 50% up to 97.6% on averaged results. Instantaneous fractions at 45Hz scanning rate varied far more than those

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ranges. Flowing fluids were generally consistent from well to well, with some exceptions, and the main features of the fluids are heavy water (from 1.175 to 1.182 SG with a few lighter waters) and sour gases (typically 2% H2S and 2.5% CO2). Those properties are summarized in Table 1.

Range of flow-rates observed during the tests are presented on Fig. 5. It is clear that with the objective of those tests being to accurately determine oil rates, more than that of gas or water, the combination of high GVF and high water cut provides a very unfavorable case in that the oil fraction is very small.

With most cases having a GVF and water cut higher than 90%, this means that the oil fraction would generally be of less than 1%. In other words, the phase being the main target of those tests represents 1% or less of the total flow line. In fact, this was typically even smaller. As shown on Fig. 6, 1.1% was the maximum case observed, with oil fractions reaching less than 0.1% in cases. Fig. 6 shows the relationship between water cut, GVF and oil volume fraction with iso-OVF lines represented.

Besides the difficulties associated with accurately measuring small fractions of the target phase, the nature of flow itself

adds to the complexity. It has been observed that in most of those wells the flow was very unstable at high frequency. In order to illustrate this, Fig. 7 represents the fractions (GVF and WLR) as well as the venturi differential pressure reported at 1 second scanning rate over a period of only 2 minutes. It can clearly be seen that from one second to the next both the fractions as well as the total flow rate can change dramatically. The behavior presented here was the norm more than the exception during those tests. The gas volume fraction, for instance, fluctuates from nearly 100% down to less than 30% during this interval. This is further highlighted by the response of the differential pressure sensor, fluctuating from 200mbar up to 1200mbar, representing significant rate instabilities over very short periods of time. It can also be understood that such behavior observed at 1Hz frequency sees further fluctuations at higher frequencies. In this respect, the high frequency of data acquisition (45Hz) is a clear requirement as averaging flowing fractions and differential pressure under such variable conditions would obviously lead to error in rates. For the purpose of illustration, the average GVF during the 2mn of data presented on Fig. 7 (equal to the total gas rate during those two minutes divided by the total multiphase volumetric production) is of 89.2%. If, instead of using high-frequency data an average measure of GVF had been used, this would have resulted in a GVF of 81.7%, leading to significant errors in both gas and liquid rates. Accounting correctly for the high-frequency rate variations in all calculations by performing full flow-rate calculations every 22ms thus proved to be a major feature of the MPFM technology used.

Fluid Properties Inputs, QA/QC and Lessons Learnt

Fluid properties model definition and empty pipes In order to set up the MPFM data computations some inputs are required to perform flow-rate calculations. First, a series of source strength measurements were performed to ensure results consistency. In total, 6 series of

measurements were performed: two before the start of operations, two in the middle and two after the end of the trials. Overall, those showed excellent consistency with deviations of typically less than 0.1%.

Second, the fluid properties models were defined for each well. This was done using simple measurements: oil density and viscosity at ambient conditions, water density at ambient conditions, gas specific gravity and non-hydrocarbon components’ concentration. Based on those inputs and using a series of proprietary properties correlations, the required properties of the three fluid phases at operating conditions are estimated, updated dynamically at every computation step to account for possible changes in pressure and temperature. The fluid properties were measured not only on samples taken before the start of operations to set up the meter, but also regularly during the actual testing sequence in order to check for the validity and consistency of those inputs. Those are summarized in Table 1.

Reference attenuations definition and validation The third and most critical step in ensuring that representative flow-rates are obtained is the accurate determination or

reference attenuations. The total mass rate depends on a representative estimate of mixture density relying on good fractions and the water cut, critical in order to reach representative oil rates at high water cuts relies mostly on the fractions calculations.

There are two ways to determine the attenuation properties of the fluids: from in-situ measurements performed on samples and from composition. For all phases those two techniques have been used for validation purposes. The oil and gas attenuations were found to be very consistent between wells and when comparing composition-derived results with measurements. The gas attenuation reference was finally setup using composition-derived inputs (based on gas lift analysis results normalized to measured H2S and CO2 content obtained from sniffer tubes) while in-situ attenuation measurements were used for the oil phase. In fact, neither the oil attenuation nor the gas attenuations showed significant variability from well to well and the focus was mostly placed on validating the water references. As the operating point as shown on Fig. 3 would be located near the gas-water line, the location of the water reference can clearly be seen as critical in order to obtain accurate water cut measurements.

The preferred approach for operational ease consisted in performing in-situ measurements of water attenuation properties.

This was done prior to the operations and for some wells repeated using samples acquired during flow. What was observed, however, was that most of the waters flowing during the tests were very strongly attenuating. This is due to large

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concentrations of salts, increasing both the water density and its attenuating properties. The combination of those two factors was such that during in-situ sequences where the MPFM was seeing 100% water only 2% of the low energy gamma-rays emitted managed to reach the detector, 98% were attenuated. In this situation, the statistics of the measurement, albeit very small in relative terms to the emitted number of gamma-rays, could have a sizeable impact over the number of counts measured. A natural radioactive source does not emit exactly the same number of gamma-rays at all times but shows some variations around an average. In addition, the collisions with the tested matter are of a random nature, leading to some variability in the measurement. With an average of only 15 gamma-ray counts per 22ms sampling interval, it is clear that even small variations of a few counts could have a significant impact. For this reason, all water in-situ measurements were carefully reviewed for data consistency and the attenuations calculations were updated to ensure the representativity of the results.

At the end of this process, the calculated attenuations were checked for consistency between wells and were compared with theoretical values assuming sodium chloride as the only source of salts. The trend of attenuations against density for the various energy levels considered is presented on Fig. 8, along with theoretical values. Several conclusions can be reached from this figure. First, measured attenuations at 356keV show a very good consistency with theoretical values. While this energy level is not used for customary rate calculations, this is still very valuable information in that the attenuation at this energy level is a function only of the fluid density. The good match observed between measurement and theory, less than 0.5% in all cases, ensures that the density inputs are accurate.

A similar trend is observed for high energy attenuation, which is expected as density is also a driving property in this case but with some deviations. Those are far more significant and clearly systematic for low energy attenuations. While a general trend is clearly observed, some variations are observed as well as attenuations far more significant than those expected. In order to validate those measurements, a water sample was acquired and analyzed for salts composition. Besides sodium chloride, still representing the majority of the salts present, a significant portion of calcium ions was found (to be expected in a carbonate formation) but more importantly, significant concentrations of potassium, magnesium and strontium. As those ions are far more attenuating than sodium, this explains the deviation from theoretical values. The composition was used to determine theoretical attenuations, which validated measured attenuations for the sampled well, consistent between wells and from repeated measurements.

Trial Results and Discussions Test procedures and repeatability

In order to validate the results, some additional considerations were taken. First, some of the tests were repeated at several days of interval under similar production conditions to assess measurement repeatability. Two pairs of tests were long enough to provide representative estimates at similar gas lift injection rates and flowing wellhead pressures. In those 2 instances, the total liquid rate was identical within +/-1% and the gas rate within +/-2.5%. As the results observed at the test separator showed similar variations, this clearly shows the consistency of the measurement.

Another verification consisted in using wellhead liquid samples to perform manual measurements of water cut. However, it was clearly observed that as the wells have a tendency to have unstable water cuts, and even when considering the average water cut from four samples, those results have to be taken with due care.

Finally, a direct quality control point of the fluids behavior model consists in comparing the MPFM total mass rate observed at operating conditions with that converted to standard conditions. As the fluid properties correlations used are largely independent of one another, this is a direct indicator of the validity of those correlations. This showed that the PVT model was always consistent (less than 1% difference), with errors generally below 0.3%. Measurements validation: mass rate comparison The results of the tests are presented in Table 3 and Table 4 for all valid tests (except for the first test on well 1 and on well 6 that were not performed using the oil build-up technique at the separator and where the separator results are considered as unvalid with respect to oil rate and water cut). The first step when comparing flow rate measurements from two different sources consists in assessing whether both sources show similar total mass rates. This quality check point aims at ensuring that, independently of fractions measured at the MPFM or without considering the quality of separation at the separator, there is no systematic difference between the two devices.

It must be pointed out that neither tool does offer a true mass measurement. The MPFM total mass rate as calculated from the Venturi differential pressure requires a correct mixture density input while for the separator, turbine meters on the liquid legs offer volumetric rates, and an orifice plate on the gas line including gas density inputs is also dependent on an accurate density input (via SG measurement corrected for gas pressure). Nevertheless, errors in total mass rate calculations should remain limited. For the MPFM this is essentially related to the fact that, except at very high GVF, the error on mixture density ought to remain small (only 3.4% at 95% GVF assuming a large 0.2% absolute error in estimated GVF fraction), and would be further reduced as the total mass rate is proportional to the square root of the density-differential pressure product (leading to a 1.7% error in the example considered). For the separator, minor imperfections in separation quality would have little incidence on the results as well.

Therefore, a comparison of total mass rate was performed and showed a good consistency between MPFM and test separator, but with a marked increase in total mass rate given by the MPFM compared to the test separator as the GVF

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increases as shown on Fig. 9. This observation proved to be very important upon review of the flow-rates of individual phases, highlighting potential causes for concern in such environment.

Results comparison

The results were compared and are presented on Fig. 10 to Fig. 12. On those figures, the published MPFM uncertainty is also presented for the purpose of validation of those specifications (presented in Table 5 for completeness). For the liquid rates, at lower GVF fractions, the measurement provides a good consistency but then starts diverging from the separator results at high GVF (>97%). In such environments, both technologies are known to have limitations, the MPFM with respect to accurate relative fractions determination with small liquid fractions and the separator with respect to the quality of separation in the presence of low liquid rates and high gas rates. In that respect, the observed differences cannot be readily attributed to the failing of one meter against an other. Both technologies were operated using best practices and as shown by Kelechi et al. (2008), low-pressure high water cut environments are known to be challenging for any technology. Nevertheless, the consistent trend observed, with the MPFM showing higher liquid rates than the separator at high GVF do point towards some possible systematic error of one technique or the other. Regarding the MPFM, this could be due to possible limitations of the way the flow structure is taken into account. At higher GVF, the nature of flow can change, to misty or annular flow for instance, which could possibly affect fractions calculations or liquid-gas slip behavior. For the separator, on the other hand, the possibility of carry-over cannot be ignored at such high gas fractions. Even though it was calculated that the retention time of the gas was typically of one minute or more, even small entrained liquid volumes could have a significant impact over the total liquid rate.

The differences in liquid rates are somewhat matched to differences observed in gas rates (Fig. 11), differences between MPFM and separator results remain within the range of uncertainty of the MPFM, within +/- 10%, however it is easy to see that the MPFM provides lower gas rates than the separator at higher GVF. This also points towards possible carry-over, with entrained liquid causing an over-reading of orifice plate differential pressure due to an increase in mixture density, or towards some errors in the MPFM’s venturi fluid mechanics model at low pressure ( J.Cazin et al 2005 ) .

It is important to mention that different computational approaches were applied to the MPFM data during a very comprehensive review of the acquired data and calculations workflow specific to this environment in order to ensure the consistency of the results, in cases using the 3rd gamma-ray energy level as an additional input in order to ensure results consistency. While the results did vary somehow depending on the process used, the trends remain the same: the separator liquid rates are always lower than the MPFM’s at higher GVF with conversely higher gas rates.

Finally, the water cut measurements appear fairly consistent between the three available sources: separator, MPFM and wellhead water cut sampling. As shown on Fig. 12, those measurements are generally within the uncertainty band of the MPFM. The wellhead water cut was found to be in line with that measured at the MPFM or test separator, without being closer from one than the other.

With respect to the oil rate, deviations are more significant, with results coinciding generally within +/-30%, but this is mostly a consequence of the uncertainty in water cut determination, both for the MPFM and for the test separator in the presence of emulsions. The MPFM is known to experience a degradation in performance at high GVF, both in terms of liquid rates estimation as well as in terms of water-cut measurement, and in this respect the separator would appear better suited. Furthermore, even a small uncertainty on water cut at very high water cut values could prove detrimental to oil rates estimations. As an example, we can see that the test on Well 9, a small difference in liquid rate (3.5%) and minor on water cut (-0.8%) still bring a 11.7% difference in terms of oil rate. Testing practices on the test separator have been devised so that such errors can remain minimal: oil build-up tests are performed specifically on low oil producers, closing the oil outlet of the separator for oil to accumulate and draining the oil to obtain cumulative volumes and hence average rates over the accumulating intervals. Furthermore, a low-rate liquid meter has been installed on the separator since the tests performed during those trials to reduce any uncertainty related to low rates. On the other hand, a key feature of the MPFM is its repeatability. Well 1 and well 6 had been repeat-tested at a few days’ interval and the results showed great consistency: differences of less than 1% on liquid rate and water cut and less than 2.5% on gas rate.

The largest difference on oil rate between MPFM and separator can be ignored as not oil build-up test was performed at the separator during that test and the result can be considered as unvalid from the separator’s standdpoint. Leaving that test aside, there is no marked trend with respect to oil rate errors against GVF. This is mostly due to the fact that a lower GVF the water cut tends to be higher. Thus even smaller deviations in water cut can still create large differences. Overall, it is difficult both a low and high GVF to assign a systematic error to any type of device. At high GVF the MPFM experiences a degradation in measurement accuracy while the separator could be more prone to carry-over, while at lower GVF liquid rates tend to be larger, thus leaving less time for the liquids to separate in the separator but the higher water cut can render the MPFM’s limited uncertainty on water cut still critical for accurate oil rates estimation.

Therefore, it can be concluded that the MPFM provided results within its range of uncertainty, consistent with the test

separator keeping in mind the limitations of both technologies and can handle the challenging environment presented by such wells. Future work in such environment should focus on two main points: review of the fluid behavior model in the MPFM for fractions and slip determination, but also assessment of possible carry-over in the test separator by acquiring samples from the

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gas line to check for the presence of any liquid. This work is still on-going as part of a collaboration between the operator and service provider.

Highlight on Specific Tests Besides the purely metrological performances of the MFPM when compared to a test separator, this technology also brings significant benefits when testing gas-lifted wells in order to optimize well productivity. Well stability or impact of gas lift injection rate have a clear influence on a well’s productivity and the MPFM can provide valuable inputs. Well 4

First, let us consider the case of the test performed on well 4. This well is located on a remote platform and, as the well was lined up to the MPFM-separator line, showed some fluctuations and took some time in providing stabilized rates. As shown on Fig. 13, the well showed flow oscillations with one hour periodicity. While the fluctuations were very high initially (over 50% of average rate), the extent of fluctuations became smaller after a few periods and the well became more stable (even though significant fluctuations were still observed at higher frequency). Also interesting to notice, the first few periods showed significant segregation in the slugging behavior: first oil slugs were getting to the meter, followed by water slugs and finally gas slugs, acting as a piston pushing the liquids. This could be explained as the effect of liquid segregation taking place in the test line, but after two periods this behavior subsided. Instead, the slugging behavior became only one of gas-liquid, with no change in water cut as oil and water remained mixed in the pipes without the liquid phases segregating. Being able to see this behavior first allows the operator to recognize the fact that the apparent unstable behavior of the well does not, over the long term, impact well performance as this effect is only short-lived. Further, even during the unstable rate sequence if can be used to determine a representative water cut as the fraction measurement stabilized much before the flow rates, showing only small instantaneous fluctuations (+/-3% around the average) after only 2 hours of test.

Well 15

Well 15 (not shown in the results as this well was not tested with the test separator) appeared to have a very unstable behavior during the tests as shown on Fig. 14. This was initially attributed to the low rates observed by the MPFM causing lift issues to arise and therefore, some doubt were cast on the test results. An additional concern was that this specific well has not been pre-selected prior to operations and appeared to be in the low range of the meter. However, when considering high-frequency data and not 15mn-averaged data as in Fig. 14, used for display purposes to smooth out results, a different behavior emerges. As can be seen in Fig. 15, the well was actually intermittent, alternating sequence of high-rate flow and only migration of gas to surface. Even though the average total liquid rate appears low (barely 470 bbl/d), 98% of the cumulative liquid flow (and 80% of the cumulative gas flow) occurs over only 1/3 of the total test time. Those sequences of flow were always marked by very high liquid rates (always spiking above 3000bbl/d), showing first a slug of oil and water (with water cut values between 30 and 85%) at relatively low GVF below 95%, followed by 100% water cut with fast-decreasing rates.

This observation brings two important conclusions: first, it clearly highlights the fact that this well is not producing under optimal conditions. If more stable rates could be achieved, the overall productivity of the well could be improved. Second, and similarly important, even though the average test conditions (99% GVF, 85% water cut, low rates) are clearly unfavorable in order to obtain accurate flow rate estimates, the fact that most of the liquids comes in slugs at much lower gas volume fractions does improve significantly the confidence level in calculated liquid rates. Furthermore, as most of the oil flows when the GVF is lowest and the water cut smaller than average, this also increases the confidence in oil rates calculated by the MPFM.

Well 10 variable-rate test

A few wells have been tested under variable production settings. One of them is well 10. For most of those tests, only short sequences under different production settings were attempted, typically 2 hours or less. As shown on Fig. 16 for well 10, this tended to be too short for the well to stabilize under variable conditions and therefore little information could be obtained to assess how a change in, in that instance, gas lift injection rate would affect the well productivity. In Fig. 16 the various colored sequences correspond to different gas lift injection rates and show that, even though no clear stabilized period exists for each sequence, it is nevertheless easy to recognize than during the middle period where a small lift gas rate was used the well was not efficient and that liquids were accumulating. This period lasted only 40 minutes and it was immediately possible to recognize that liquids accumulated. The subsequent increase in gas lift rate led to a recovery of the liquids accumulated during that sequence, evidenced by higher water and oil rates than observed during the first period of flow. Within a two-hour period, the flowing ratios, and especially the gas volume fraction indicative of the gas/liquid ratio stabilized again. This is an illustration of how the lift capacity of a well can be assessed in real time without risking affecting the well by letting too much liquid accumulate in the well, thus killing it.

Permanent Installations Implementations and Deployment Strategy Following those trials, it was determined that the tested MPFM technology is suitable for production testing applications in Total ABK wells. Some expected limitations were observed, such as the loss of accuracy at high GVF or the uncertainty on water cut but overall the performance achieved was found suitable for the target application and does not deviate significantly from the expected performance of the test separator. Furthermore, the high-frequency data acquisition has been shown to have positive implications in terms of well performance monitoring and optimization.

SPE 118148 9

Based on the results from these trials, all wells operated by Total ABK were considered for sizing and suitability purposes, including the latest test data as well as historical minimum and maximum rates to take into account possible variations in well performance. Besides ensuring that the MPFM would operate within it calibrated differential pressure range, the field trial results were included by using not only the gas volume fraction but also specifically the oil volume fraction as parameters of importance. Similarly to the suitability study performed for well selection prior to the trials, each well was given a suitability index, defining whether each well operates in suitable, near-limit or unsuitable conditions.

At the end of this study, it was determined that out of 66 wells considered, 30 can be considered as suitable candidates, 18 would be in more challenging conditions and 18 would be testable only for trending purposes and not necessarily targeting good metrological performances. In order to optimize the MPFM utilization, it was decided to locate it on a remote platform, from which 48 wells could be tested. Out of those, 24 are suitable and only 10 are out of range. The approach in this situation is to ensure that the length of the test lines are minimized so that wells can stabilize faster than when tested from a far away platform. In this environment, it can be expected that each well will be tested at least once a month and possibly twice a month for some key wells. This increase in test frequency, and overall improved ease of operations as the MPFM can be assimilated to an instrumented length of pipe, will improve the monitoring strategy. Repeatability of the measurement has been proven and should also help reduce the test rejection rate.

Key to maximizing the benefits from the implementation of the MPFM will be the quality of training of the operator’s personnel to this technology as well as the strength of support from the vendor. Not only must the meter be properly setup for each well (defining fluid properties and reference attenuations), but should also be followed for any possible change, especially in terms of water salinity. Setting up the meter for a specific well requires only atmospheric samples capture to perform basic properties and in-situ measurements. The entire operation to characterize the fluids takes only one hour, which makes data validation or re-processing straightforward if such update of input parameters is required, which might only be rarely the case, for instance in the case of injection water breakthrough leading to a significant reduction in water salinity.

Conclusions This paper presented the results of a comprehensive trial of a compact, dual-energy gamma-ray/Venturi meter in a challenging environment with large gas fractions and high water cuts and showed that it performs within the same range of uncertainty as that expected from a test separator. Furthermore, it provides a better insight into the dynamic nature of flow from a well thanks to its high frequency of acquisition, allowing for the diagnostic and remediation of well productivity impairments.

Key to ensure representative results is the determination of quality inputs, be there in terms of fluid PVT properties, but more importantly in such an environment to account properly for the nuclear attenuation behavior of the fluids, and especially that of highly-attenuating water. Some more advanced review of the fluid mechanics behavior should also be performed in order to ensure the validity of data interpretation workflow.

Throughout the trial, from first discussions to execution and results analysis, a joint approach has been used between the operator and service company, both drawing expertise and knowledge from local representatives in the UAE as well as from global worldwide experts located in headquarters. The open discussions and collaborative approach led to achieving good results and was key to the success of this trial.

Furthermore, a comprehensive review of the inputs and calculation principles for both technologies to improve the quality of metering in such situations is still an on-going task, using the results from those tests in order to define areas of work for future improvements.

Building on those lessons learnt, it is important to highlight that expertise transfer via adequate training will be fundamental to the implementation of a permanent MPFM for Total ABK, keeping a good communication and knowledge exchange between operator and vendor.

10 SPE 118148

Nomenclature A Mass attenuation (m2/kg) ABK Abu Al Bukhoosh (-) D Diameter (m) GVF Gas Volume Fraction (-) MPFM Multi-Phase Flow-Meter (-) N Gamma-ray counts (1/s) OVF Oil Volume Fraction (-) WC Water cut (-) WLR Water/liquid ratio (-) α Holdup (-) ρ Density (kg/m3) Subscripts g Gas o Oil w Water Superscripts LE Low energy HE High energy

Acknowledgments The authors wish to thank both Total and Schlumberger management for allowing the publication of this work.

Furthermore, the work of Bernard Theron (Schlumberger) and Jean-Grégoire Boero-Rollo (Total) in this project provided crucial inputs and must be recognized.

References Cazin ,J , Couput J-P , Dudezet C , Escande J., Gajan P., Lupeau A.,Strzelecki A. , Lessons from wet gas flow metering systems using differential measurements devices , NSFMW 2005 Couput , JP , 2001. Operational experiences in multiphase metering implementation. Paper NSFMW 2001 Kelechi, I.O. and Edwards, J. 2008. Reliability of Multiphase Flowmeters and Test Separators at High Water Cut. Paper SPE 114128

presented at the SPE Western Regional and Pacific Section AAPG Joint Meeting, Bakersfield, California, 31 March–2 April Pinguet, B.G., Roux, G. and Hopman, N. 2006. Field Experience in Multiphase Gas-Well Testing: The Benefit of the Combination of

Venturi and Gamma Ray Fraction Meter. Paper SPE 103223 presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24-27 September

Poyet, J-P, Ségéral, G. and Toskey, E. 2002. Real-Time Method for the Detection and Characterization of Scale. Paper SPE 74659 presented at the SPE Oilfield Scale Symposium, Aberdeen, United Kingdom, 30-31 January

Theuveny, B.C., Ségéral, C. and Pinguet, B. 2001. Multiphase Flowmeters in Well Testing Applications. Paper SPE 71475 presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 30 September–3 October.

SPE 118148 11

Tables

Table 1-Fluid properties

Well Oil Density

Oil Viscosity

Water Density Gas SG Gas H2S

fraction Gas CO2 fraction

_________ __kg/m3__ cP @ 15.5ºC __kg/m3__ __Air=1__ ____%____ ____%____

Well1 858.0 32.5 1177.2 0.746 2.05 2.00 Well2 844.0 21.8 1156.5 0.732 1.40 2.00 Well3 850.0 10.5 1175.2 0.720 2.05 3.00 Well4 858.0 45.9 1182.0 0.732 0.75 2.00 Well5 885.0 148.0 1136.5 0.748 3.50 2.00 Well6 877.0 52.3 1180.0 0.713 0.75 2.00 Well7 851.0 44.3 1177.2 0.723 1.80 2.00 Well8 848.0 65.6 1180.7 0.701 2.00 3.00 Well9 873.0 25.0 1175.2 0.720 1.00 1.00

Well10 860.0 15.0 1074.4 0.725 1.70 2.00 Well11 858.0 23.0 1040.7 0.710 1.95 2.50 Well12 864.0 20.1 1129.3 0.718 1.50 2.00 Well13 883.7 30.6 1164.6 0.701 2.20 2.50 Well14 866.3 12.7 1171.2 0.730 2.20 2.00 Well15 890.6 28.1 1154.6 0.701 2.70 1.80

Table 2-attenuation methods used

___In-situ___ ___Composition___ _________Comments_________

Gas Yes Yes Composition normalized for H2S and

CO2 content

Oil Yes Yes (one sample) Little variability, consistent results between composition and in-situ

Water Yes Yes (one sample) Strong impact of specific ions

Table 3-Results of main tests - MPFM

Well . Test Date .

___MPFM___ _______________MPFM Production Rates and Fractions______________

Temp. Press..

Oil Rate @ SC

Water Rate @ SC

Liquid Rate @ SC WC Total Gas

Rate @ SC GVF

________ __________ __°C_ _barg_ __stb/d__ __stb/d__ __stb/d__ __%__ _MMscf/d_ __%__ Well1 23-Apr-07 76 9.9 116 4798 4914 97.6 1.650 97.5 Well2 23-Apr-07 35 11.9 710 4056 4766 85.1 5.530 95.1 Well3 24-Apr-07 44 8.9 237 585 822 71.2 1.720 98.1 Well4 24-Apr-07 39 11.6 636 3486 4122 84.6 5.500 88.9 Well5 25-Apr-07 43 9.1 371 437 808 54.1 2.240 96.8 Well6 25-Apr-07 80 10.9 310 5540 5850 94.7 2.650 91.6 Well7 26-Apr-07 34 11.5 293 2802 3095 90.5 6.230 95.7 Well8 26-Apr-07 32 9.1 153 2270 2423 93.7 1.440 97.5 Well9 27-Apr-07 68 12.0 371 3747 4118 91.0 5.900 95.1

Well11 28-Apr-07 25 9.3 459 770 1229 62.7 3.530 98.0 Well12 29-Apr-07 57 9.9 166 2269 2435 93.2 2.750 95.2 Well6 29-Apr-07 79 10.9 264 5614 5878 95.5 2.710 89.1

Well13 29-Apr-07 25 9.1 179 993 1172 84.7 2.540 97.5 Well1 30-Apr-07 77 9.7 152 4718 4870 96.9 1.610 86.6

12 SPE 118148

Table 4-Results of main tests – Separator and comparison

Well . _______Separator Production Rates and Fractions________ ___Differences (MPFM/separator)___

Oil Rate @ SC

Water Rate @ SC

Liquid Rate @ SC Water cut Total Gas

Rate @ SCLiquid Rate

Gas Rate

Oil Rate

Water cut

________ __stb/d__ __stb/d__ __%__ _MMscf/d

_% (rel) % (rel) % (rel) % (abs)

__stb/d__

Well1† 140 4864 5004 97.2 1.600 -1.8% 3.1% -17.1% 0.4% Well2 556 4019 4575 87.8 5.680 4.2% -2.6% 27.7% -2.7% Well3 253 442 695 63.6 1.790 18.3% -3.9% -6.3% 7.6% Well4 486 3486 3972 87.8 4.970 3.8% 10.7% 30.9% -3.2% Well5 233 406 639 63.5 2.480 26.4% -9.7% 59.2% -9.5% Well6† 55 5713 5768 99.0 2.600 1.4% 1.9% 463.6% -4.3% Well7 304 2720 3024 89.9 5.980 2.3% 4.2% -3.6% 0.6% Well8 118 2235 2353 95.0 1.390 3.0% 3.6% 29.7% -1.3% Well9 332 3734 4066 91.8 5.700 1.3% 3.5% 11.7% -0.8%

Well11 232 685 917 74.7 3.770 34.0% -6.4% 97.8% -12.0% Well12 218 2177 2395 90.9 2.650 1.7% 3.8% -23.9% 2.3% Well6 164 5665 5829 97.2 2.600 0.8% 4.2% 61.0% -1.7%

Well13 126 949 1075 88.3 2.500 9.0% 1.6% 42.1% -3.6% Well1 221 4656 4877 95.5 1.600 -0.1% 0.6% -31.2% 1.4%

† The first test on well 1 and on well 6 were not performed using the oil build-up technique at the separator and the separator results are considered as unvalid with respect to oil rate and water cut.

Table 5-MPFM accuracy specifications

Gas Volume Fraction Range (%)

__0 to <90__ _90 to <96_ __96 to 98__ Gas flow rate relative uncertainty Pressure ≥ 20bara [300psia] ± 5 ±5 ± 5 Pressure < 20bara [300psia] ± 10 ± 15 ± 15 Liquid flow ate relative uncertainty ± 2.5 ± 5 ± 10 Water/liquid ratio absolute uncertainty ± 2.5 ± 2 to ± 5 ± 5 to ± 8

Figures

ΔP

SourceDetector

Flow

Venturi

T

PΔPΔP

SourceDetector

Flow

Venturi

T

P

Fig. 1 – central facilities where the tests were conducted

Fig. 2 - Schematic of MPFM data acquisition setup

SPE 118148 13

-25

-20

-15

-10

-5

0-90 -80 -70 -60 -50 -40 -30 -20 -10 0

Low Energy Linear Attenuation, 1/m

High

Ene

rgy

Line

ar A

ttenu

atio

n, 1

/m

100% Gas100% Oil100% Water70% GVF 67% WC

Fig. 3 - Nuclear attenuation triangle

Fraction Distribution (at 10 barg)

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

90.0

100.0

84.0 86.0 88.0 90.0 92.0 94.0 96.0 98.0 100.0

GVF (%)

WC

(%)

Primary SelectionSecondary SelectionOut of RangeSelected

Fig. 4 - Candidate selection process: classification

0

1000

2000

3000

4000

5000

6000

7000

0 1 2 3 4 5 6 7

Gas Rate (MMscf/d)

Liqu

id R

ate

(bbl

/d)

Fig. 5 - Range of flow-rates observed during the test

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

100.00

86 88 90 92 94 96 98 100

GVF (%)

WC

(%)

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

OVF

(%)

OVF=0.1% OVF=0.2%OVF=0.5% OVF=1%Test Results Observed OVF (%)

Fig. 6 - oil volume fractions observed during the tests

0

10

20

30

40

50

60

70

80

90

100

2:00:00 2:00:20 2:00:40 2:01:00 2:01:20 2:01:40 2:02:00

Time

WLR

and

GVF

(%)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

Diffe

rent

ial P

ress

ure

(mba

r)

WLR GVF DeltaP Venturi

Fig. 7 - evidence of large high-frequency fluctuations

-0.080

-0.075

-0.070

-0.065

-0.060

-0.055

-0.050

-0.045

-0.040

-0.035

-0.030

1000 1020 1040 1060 1080 1100 1120 1140 1160 1180 1200Water Density (kg/m3)

LE M

ass

Atte

nuat

ion

(m2/

kg)

-0.020

-0.019

-0.018

-0.017

-0.016

-0.015

-0.014

-0.013

-0.012

-0.011

-0.010

HE, 3

56 k

eV M

ass

Atte

nuat

ion

(m2/

kg)

Theoretical LE att Measured LE attTheoretical HE att Measured HE attTheoretical 356keV att Measured 356 keV att

Fig. 8 - water reference attenuations

-4.0%

-2.0%

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

16.0%

18.0%

86.0 88.0 90.0 92.0 94.0 96.0 98.0 100.0

GVF (%)

Mas

s ra

te d

iffer

ence

Fig. 9 - mass rate comparison

-20.0%

-10.0%

0.0%

10.0%

20.0%

30.0%

40.0%

86.0 88.0 90.0 92.0 94.0 96.0 98.0 100.0

GVF (%)

Rela

tive

diffe

renc

es M

PFM

/sep

arat

or Liquid rate differenceStated MPFM uncertainty

Fig. 10 – liquid rate differences and MPFM performances

14 SPE 118148

-20.0%

-15.0%

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

20.0%

86.0 88.0 90.0 92.0 94.0 96.0 98.0 100.0

GVF (%)

Rela

tive

diffe

renc

es M

PFM

/sep

arat

or

Gas rate differenceStated MPFM Uncertainty

Fig. 11 – gas rate differences and MPFM performance

-15.0%

-10.0%

-5.0%

0.0%

5.0%

10.0%

15.0%

86.0 88.0 90.0 92.0 94.0 96.0 98.0 100.0

GVF (%)

Abso

lute

diff

eren

ces

MPF

M-s

epar

ator

Water cut differenceStated MPFM Uncertainty

Fig. 12 – water cut comparisons

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

22:00 00:00 02:00 04:00 06:00 08:00

Date-Time

Liqu

id R

ates

(stb

/day

)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

Gas

Rate

(mm

scf/d

ay)

qo_sc [bbl/d]qw_sc [bbl/d]qg_sc [MMscf/d]

Fig. 13 – Flow rates during testing on well 4

0

100

200

300

400

500

600

700

800

900

1000

12:00 14:00 16:00 18:00 20:00 22:00 00:00

Date-Time

Liqu

id R

ates

(stb

/day

)

0.00

0.50

1.00

1.50

2.00

2.50

Gas

Rate

(mm

scf/d

ay)

qo_sc [bbl/d] qw_sc [bbl/d] qg_sc [MMscf/d]

Fig. 14 – Averaged flow rates during the test on well 15

0

500

1000

1500

2000

2500

3000

3500

4000

16:00 16:30 17:00 17:30 18:00 18:30 19:00

Time

Liqu

id ra

tes

(bbl

/d)

0

1

2

3

4

5

6

7

8

Gas

rate

(MM

scf/d

)

qo_sc [bbl/d] qw_sc [bbl/d] qg_sc [MMscf/d]

Fig. 15 – Instantaneous flow rates in well 15

0

200

400

600

800

1000

1200

10:00 12:00 14:00 16:00 18:00 20:00 22:00 00:00 02:00 04:00 06:00

Date-Time

Liqu

id R

ates

(stb

/day

)

0.00

0.40

0.80

1.20

1.60

2.00

2.40

Gas

Rate

(mm

scf/d

ay)

qo_sc [bbl/d]qw_sc [bbl/d]qg_sc [MMscf/d]

0

200

400

600

800

1000

1200

10:00 12:00 14:00 16:00 18:00 20:00 22:00 00:00 02:00 04:00 06:00

Date-Time

Liqu

id R

ates

(stb

/day

)

0.00

0.40

0.80

1.20

1.60

2.00

2.40

Gas

Rate

(mm

scf/d

ay)

qo_sc [bbl/d]qw_sc [bbl/d]qg_sc [MMscf/d]

Fig. 16 – test performed on well 10 under variable gas lift rate