30 Oilfield Review

Multiphase Fluid Samples: A Critical Piece of the Puzzle

A new multiphase sampling tool allows operators to capture representative fluids

without separation equipment. The ability to accurately analyze fluid composition in

real time creates opportunities for them to replace conventional testing equipment

with more-efficient and often more-accurate multiphase flowmeters.

Vitaliy AfanasyevNoyabrsk, Russia

Paul GuiezeAlejandro SchefflerClamart, France

Bruno PinguetMaturin, Venezuela

Bertrand TheuvenyMoscow, Russia

Oilfield Review Summer 2009: 21, no. 2.Copyright © 2009 Schlumberger. For help in preparation of this article, thanks to Mahdi Baklouti, Olivier Loicq, Federico Ortiz Lopez and Gerald Smith, Clamart; and David Harrison, Houston.PhaseSampler, PhaseTester, PhaseWatcher, PVT Express and Quicksilver Probe are marks of Schlumberger.

Poor well test data can be as bad as no well test data, especially for those charged with field development planning or production manage-ment. Applying unreliable results to long-term planning—particularly when modeling large or complex reservoirs—inevitably leads to less-

than-optimal drainage strategies. Measurements are often distorted by such common events as wells flowing at rates beyond the test separator capacity or well fluids arriving at surface in the form of foams, oil-water emulsions, heavy oils or condensate-laden wet gas.

1. Mullins OC, Elshahawi H, Flannery M, O’Keefe M and Vanuffellen S: “The Impact of Reservoir Fluid Compositional Variation and Valid Sample Acquisition on Flow Assurance Evaluation,” paper OTC 20204, presented at the Offshore Technology Conference, Houston, May 4–7, 2009.

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Efficient production of formation fluids requires accurate predictions about how tem-perature and pressure changes that always accompany reservoir depletion affect the con-stituent fluid and formation properties. In remote areas and on deepwater platforms, lack of infra-structure, space and weight restrictions and transport logistics can make traditional testing and metering equipment impractical. Fluids pro-duced in deep water—cooled by their trip to the surface through thousands of feet of pipe in near-freezing water—sometimes cannot be heated to a temperature sufficient to accomplish separation.

At the same time that the industry is strug-gling with those challenges, an increasing portion of operators’ portfolios is made up of the type of reserves historically avoided because they are difficult to produce economically. These include heavy oils, wet gas and other unconventional fluids that defy phase separation.

In installations where weight and space must be taken into consideration or where complex fluids make phase separation difficult, multi-phase flowmeters (MPFMs) are quickly gaining acceptance as an alternative to traditional sepa-rators and test units. They are more convenient and have a smaller footprint than traditional separator-based meters and test units, and they can be used to measure flow rates without prior separation of fluids into phases (above). Additionally, the fact that MPFMs are flow-through devices means they are safer to operate and do not generate disposable fluids. In con-trast, separators must contain fluids under pressure and elevated temperatures for some period of time to effect separation.

Until recently, however, the effectiveness of MPFMs was hobbled by a significant drawback: Confidence in the accuracy of flow rates calculated without separation was limited by the absence of representative fluid samples for validation. Such samples are critical for deter-mining in situ volumetric ratios and dry gas properties used to minimize uncertainties in flow measurements.

Another method of downhole sampling uses wireline tools to capture the fluid and keep it in a chamber at in situ conditions while it is brought to the surface and then transported to a labora-tory for analysis. Because this process includes the risk and expense of a well intervention, many operators prefer to take samples at a separator on the surface.

The accuracy of downhole sample analysis is also hampered by the need to acquire samples in

a manner that ensures they are indeed represen-tative of the entire reservoir. But reservoir fluid properties are variable, and laboratory evalua-tion must be understood in the context of the spatial distribution of complex fluids within the reservoir. Unrecognized formation compartmen-talization increases the uncertainty of downhole sampling. Reservoirs with multiple compart-ments can yield very different fluids within one production zone and affect overall recovery.1

To address these issues, Schlumberger has developed the PhaseSampler fluid sampling and analysis system to be used in conjunction with a PhaseTester portable MPFM or the permanently installed PhaseWatcher MPFM. The sampling tool is small enough to be fitted to the MPFM and is easy to use (below). Laboratory tests using this combination of services to calculate flow rates and properties of conventional fluids yielded

> Smaller and lighter. The traditional test separator (left ) has a footprint of 5.68 by 2.24 m, is 2.45 m high [18.7 by 7.4 by 8.0 ft] and weighs 15,000 kg [33,000 lbm]. By comparison, the PhaseTester MPFM (right) measures 1.50 by 1.65 m, is 1.77 m high [4.92 by 5.41 by 5.81 ft] and weighs 1,700 kg [3,750 lbm].

> Simple attachment. The PhaseSampler multiphase sampling device (inset) fits on the sampling port of the PhaseTester or PhaseWatcher MPFM. Compact and easily attached, it requires no additional external power.

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answers that are as accurate as those achieved by traditional methods.

Laboratory results have also proved that the use of MPFMs to test wells flowing heavy oil and wet gas delivers a more accurate picture of the transient evolution of flow, volumes and rates than is possible with traditional separators.2 Phase separation can rarely be achieved with the efficiency required to deliver truly accurate flow calculations.

Determination of fluid properties, calculation of flow rates and prediction of fluid behavior are inseparable elements in developing reservoir drainage strategies. Accurate determination of each becomes more critical with increasing fluid and reservoir complexity. That is because the test results that once were considered not much more than a common tool for decisions on whether to complete a well have today become an indispens-able data source for modeling and development planning. Production data from inline MPFMs are used to forecast the onset of problems as wells age and the composition of fluids changes with temperature and pressure variations.

This article examines the multiphase sampling tool recently developed by Schlumberger and how it complements multiphase meters by enabling capture of fluid samples without traditional sepa-rators. A case history from Siberia illustrates how flow rates can be improved using multiphase sam-pling and meters to test remote gas-condensate wells. Another from Algeria demonstrates the accuracy of results achieved using the new sampling system to determine fluid properties.

Shrinking the Margin of ErrorMPFM technology is based on differential- pressure measurement in a venturi spool—a well-known method for single-phase flow mea-surement that can be adapted for multiphase flow by adding a nuclear component to measure total mass flow rate and the holdups, or fractions, of gas, oil and water (above).3 The resulting well test data are used to diagnose production anoma-lies continuously rather than periodically as must be done using separators. Also, data can be gath-ered during well cleanup—which increases understanding of possible flow assurance prob-lems, offers better well-performance assessment and reduces test times. This is an impossibility

using traditional separators that must remain off line until the well has returned drilling fluids or other contaminants introduced into the forma-tion during drilling and completion.

Immediate economic benefits of using MPFMs for well testing include a reduced footprint. Also, because little or no stabilization time is required, it is possible to test more wells per unit of time. These are especially attractive characteristics in remote and deepwater locations where conserving time and space is essential to project economics.

As a production-monitoring tool, MPFMs exhibit excellent response to fluctuating flow; require little or no stabilization time; and are not affected by complex flow regimes such as slugs, foams or emulsions. Because their opera-tion is insensitive to changes in flow rate, phase holdup or pressure regime, they require no pro-cess control. These capabilities give operators a means to recognize such time-dependent events as a change in flow regime or the onset of hydrate formation. In turn, wellsite engineers are able to adjust well treatment programs, flow rates or other parameters before they impact production efficiency.

MPFM devices measure flow rates at line conditions. As a consequence, engineers must turn to PVT calculations to convert these results to the standard conditions used to compute oil, water and gas flow rates. Three sets of PVT data are required to calculate flow rates at stan-dard conditions: densities, volumetric conversion factors (from line to standard conditions) and solution ratios. The liquid viscosity at line condi-tions must also be considered when heavy oil is one of the phases.

These data are obtained through analyses of samples collected at the surface or—when feasible—acquired downhole with a wireline tool, such as the Quicksilver Probe sampler.4 In a multiphase environment, samples may be col-lected at the surface in two ways. The first is to capture a known volume of a representative mix of each phase from a traditional three-phase separator. The second approach is to collect a set of representative phase samples (oil, water and gas) at line conditions and use independent mea-surements of each of the phase fractions in the commingled flow to reconstruct the whole fluid.5

Separator SamplingThe validity of flow rates calculated from samples taken at a separator is questionable because a correct analysis depends on thermodynamic equilibrium, in which both liquid and gas are at the same pressure and temperature and in equi-librium with each other.

>Multiphase metering technique. PhaseTester MPFM technology is based on measuring mass flow rate in the venturi spool using differential-pressure sensors—a well-established method for flow rate metering in a single-phase flow regime. A barium source emits gamma rays whose attenuation is measured at two different energy levels. Measuring this attenuation in multiphase media allows calculation of the density of the fluid and the mass/volume fractions of the oil, water and gas. The combination of these techniques with mathematical models provides information about the oil, water and gas production. Engineers use the well test data to continually diagnose production anomalies, quickly resolve problems and efficiently produce wells. This technology can also capture flow rate measurement data during cleanup.

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While discussions continue as to when and at what point in the separation process true equilibrium is reached, experts widely acknowledge that such a condition is reached a few feet after the fluid passes a choke, a change in pipe size or other pressure loss–generating flowline assembly. As a consequence, the temperature and pressure of the phases within a sample taken from a flowline are often not at equilibrium.6 Additionally, it is impossible to take high-pressure samples and, when one phase is dominant, significant carry-over or carry-under can occur and distort flow measurements.7

Once samples of each phase are collected, there are several options for generating fluid prop-erties. These include the use of black oil models (BOMs) to estimate fluid properties from stock-tank measurements; wellsite measurements; equation-of-state (EOS) calculations using PVT data generated during field exploration and appraisal stages; or a full PVT laboratory analysis.

Black oil models are based on statistical func-tions that assume reservoir fluid consists of three phases—oil, water and gas. Pressure, tempera-ture and density are inputs and fluid composition is included in the statistical measurement from which the correlations are derived. EOS models incorporate more fluid properties than BOMs and are more scientifically defined, but they are only as accurate as the PVT data analysis. These mod-els are ineffective when PVT data are no longer representative of the fluids because they have changed in response to pressure and tempera-ture variations. The response when such conditions are recognized is to approximate some of the necessary data, raising the level of uncer-tainty to that of the BOM.

To ensure accuracy in wellsite measurements they must be acquired by experts. PVT laboratory analysis can be time-consuming, though this may not be an issue if accuracy is more important than lost production time. Calculations are derived from correlations that may limit accuracy in certain fluids and that are particularly imprac-tical for use in heavy oils and gas condensates.

Line SamplingCollecting representative phase samples at line conditions reduces the uncertainties introduced by pressure, temperature and effluent variations.

In some cases, however, the complexity of the multiphase flow regime makes it impossible to sample a single phase at a time. To overcome this challenge, researchers developed the PhaseSampler system, designed for sampling from areas within the flow stream where one phase is dominant and the oil, gas and water are

at equilibrium at line conditions. The system hardware includes•a three-probe sampler that fits into the flow-

meter port •anopticalphasedetectortosensethetypeof

fluid entering or leaving the sample chamber•a kit that allows direct measurement at the

wellsite of key fluid property inputs at line and standard conditions for any type MPFM

•dedicated data-acquisition software thatreceives the measured fluid properties as an alternative to the correlation available with standard multiphase meters.

Through the sampling trap, the probes are placed in the flowline’s multiphase stream so that the venturi is in front of the probes. This positioning ensures the sample is well mixed and not affected by fluid slugs or similar flow anoma-lies and is therefore representative of the flow being measured by the venturi. Two of the probes face upstream to capture mostly liquids; one is placed at the bottom of the pipe, one at the top. The third probe is positioned in the middle of the flow path, facing downstream, and captures a sample that is predominantly gas (below). The captured fluid remains in a phase-segregating

>Multiphase sampling. The location and orientation of the PhaseSampler probes within the flow stream enable them to collect discrete, phase-concentrated samples at line conditions. Two probes—one at the top and one at the bottom of the flow path—face upstream and collect samples that are predominantly liquid. The third probe is in the center of the pipe and faces downstream. Numerous experiments have shown this alignment minimizes the amount of liquid entering the tube and results in the capture of a sample that is predominantly gas.

Rick_Fig04_1

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2. Afanasyev V, Theuveny B, Jayawardane S, Zhandin A, Bastos V, Guieze P, Kulyatin O and Romashkin S: “Sampling with Multiphase Flowmeter in Northern Siberia—Condensate Field Experience and Sensitivities,” paper SPE 115622, presented at the SPE Russian Oil & Gas Technical Conference and Exhibition, Moscow, October 28–30, 2008.

3. For more on multiphase flow measurement: Atkinson I, Theuveny B, Berard M, Conort G, Groves J, Lowe T, McDiarmid A, Mehdizadeh P, Perciot P, Pinguet B, Smith G and Williamson KJ: “A New Horizon in Multiphase Flow Measurement,” Oilfield Review 16, no. 4 (Winter 2004/2005): 52–63.

4. For more on Quicksilver Probe technology: Akkurt R, Bowcock M, Davies J, Del Campo C, Hill B, Joshi S, Kundu D, Kumar S, O’Keefe M, Samir M, Tarvin J,

Weinheber P, Williams S and Zeybek M: “Focusing on Downhole Fluid Sampling and Analysis,” Oilfield Review 18, no. 4 (Winter 2006/2007): 4–19.

5. Afanasyev et al, reference 2.6. Hollaender F, Zhang JJ, Pinguet B, Bastos V and

Delvaux E: “An Innovative Multiphase Sampling Solution at the Well Site to Improve Multiphase Flow Measure-ments and Phase Behavior Characterization,” paper IPTC 11573, presented at the International Petroleum Technology Conference, Dubai, UAE, December 4–6, 2007.

7. Carry-over (liquids in the gas line) and carry-under (gas in the liquids line) may result when a separator design is ill-suited to the flow regime. Either can affect the accuracy of multiphase flow rate measurements.

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sample chamber until a sufficient volume of the targeted phase is collected (below).

The single-phase sample is then placed in a flash apparatus for measurement of fluid proper-ties or it is transferred into a sample bottle for

transport to a PVT laboratory for a recombina-tion PVT study.8 The higher accuracy of the GOR resulting from the improved characterization of MPFM measurements enables a more-reliable recombination and subsequent PVT analysis.

It is important to the recombination that captured samples be validated. To that end, Schlumberger developed a quality assurance/ quality check (QA/QC) concept that includes sampling QA, rapid sampling QC, saturation-pres-sure determination and a cross-check with separator or downhole sample when available. Of these, the most powerful QC tool is PVT Express onsite bubblepoint determination at sampling temperature (next page).

Successful replication of the initial formation fluid from recombination depends on a number of variables including reservoir conditions, well parameters and sampling procedures. For exam-ple, if the bottomhole flowing pressure is below the initial dewpoint pressure, the formation fluid will be diphasic; liquids deposited in the forma-tion or in the near-wellbore region will not be lifted. Consequently, recombination will reflect only flowline fluids.

Recombination is accomplished by either physical or mathematical means. Physical recom-bination requires single-phase samples of the gas, oil or water and a gas/liquid ratio obtained through MPFM measurements. Though no physi-cal experiments are required for mathematical recombination, additional information is needed. These inputs include liquid density at recombina-tion conditions, molecular weight of the liquid, gas expansion factor and liquid/gas ratios.

Although the physical approach requires more time and personnel investment and is more subject to human error, it also offers significant advantages over mathematical recombination. These include•tangible results in the form of monophasic

samples•lessuncertaintythanfromcalculations•opportunityforfurtheranalyses•experimentalsaturationpoint•insituandstock-tankdensities.

Recombination allows the development of a compositional model for a monophasic fluid at either formation or producing conditions. Physical recombination enables this model to be fine-tuned at experimental reference points. An EOS is then used to simulate complex tests. The resulting formation-fluid model can be used to understand the drainage behavior of a field and can be applied to its exploration, development, production and forecasting.9

A Different ApproachCertain situations make it difficult to use tradi-tional separators to gain insight into a field’s drainage behavior. For instance, in fields with

> Isolating one phase. Fluids captured by a probe (top, black arrow) enter a sample chamber (middle left) where an optical phase detector distinguishes between oil, water and gas. This dynamic fluid profiling continues throughout the sampling process. The nontarget phases are displaced from the chamber back into the flowline by a hydraulically activated piston (middle right, bottom left—water flowline from bottom not shown) until only the phase of interest remains (bottom right).

Optical phase detector

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Optical phase detector

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high gas volume factors (GVFs), samples must be truly representative or the PVT properties will not have the accuracy necessary for correct rate calculations.10 These samples may be hard to capture by traditional means that rely on good phase separation—a difficult task where such fluids are concerned.

In 2007, after years of calculating flow rates through periodic conventional testing, operator Rospan International began investigating a multi-phase well testing program to refine the geological and dynamic models of its Urengoyskoe gas- condensate field in northern Siberia. The decision was based on the need for a more thorough under-standing of drainage behavior because most reservoirs had been produced at conditions below the dewpoint. Despite depletion from earlier pro-duction, analysts determined the reservoirs would support substantial future production.11

The field, discovered in 1966, is 80 km [50 mi] south of the Arctic Circle. Capturing representa-tive fluid samples from this location and then transporting them for analyses at a laboratory thousands of miles away would be impractical and expensive. Also, conducting traditional well tests and interpreting the data are made difficult by complicated reservoir structures, relatively high formation pressures and the physical and chemical properties of the produced fluids.

Most production comes from the deep Achimov Formation that lies more than 3,000 m [9,800 ft] below the surface. It is characterized by sandstones and siltstones with claystone bands, irregularly distributed reservoirs and sig-nificant lithological facies variations. Net-pay thickness ranges from 0 to 5 m [0 to 16 ft] for oil zones and from 0 to 60 m [0 to 197 ft] for gas intervals. Average porosity ranges from 15% to 18%. Oil saturation is 60% and gas saturation var-ies from 56% to 77%.12 Formation pressure ranges from 530 to 660 bar [7,700 to 9,570 psi] and for-mation temperature from 17°C to 91°C [62°F to 196°F]. GVF is between 97% and 99.5%.

Rospan addressed the issues of great dis-tances and complex reservoirs through the use of a PhaseTester multiphase flowmeter and the PhaseSampler device. The Schlumberger PVT Express portable laboratory service was used to deliver onsite compositional analysis of gas and gas condensate without phase changes. These samples were used for sample validation and fluid-properties characterization.13

In one well, a PhaseSampler tool captured fluid at the MPFM and a downhole single-phase sampler captured a bottomhole fluid sample.

> Quality assurance and check. Saturation pressure obtained at sampling temperature can be used to validate samples from multiphase sampling devices. The bubblepoint for the liquid sample (top) and the dewpoint for the gas sample (not shown) should equal the sampling pressure. When a valid sample is taken—at line conditions and in thermodynamic equilibrium—phase envelopes for liquid and gas cross at the sampling point (bottom). For quality purposes, the acceptable deviation of measured bubblepoint from sampling is ±5%. Because the dewpoint is more difficult to detect, the allowed deviation is ±20%. (adapted from Afanasyev et al, reference 2.)

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8. A flash apparatus facilitates observation of fluid phase behavior at the moment sample pressure is instantaneously released to atmospheric pressure.

9. Afanasyev et al, reference 2. 10. GVF is the gas volume at reservoir conditions divided by the

gas volume at standard conditions. This factor is used to convert surface-measured volumes to reservoir conditions. An oil formation volume factor is used to convert surface-measured oil volumes to reservoir volumes.

11. Romashkin S, Afanasyev V and Bastos V: “Multiphase Flowmeter and Sampling System Yield Real-Time Wellsite Results,” World Oil 230, no. 5 (May 2009): 66–70.

12. Gas saturation is the relative amount of gas in the pore space of a formation, usually expressed as a percentage.

13. Bastos V and Harrison D: “Innovative Test Equipment Expedites Data Availability,” E&P 82, no. 2 (February 2009): 64–65.

For more on PVT Express technology: Akkurt et al, reference 4, and Betancourt S, Fujisawa G, Mullins OC, Carnegie A, Dong C, Kurkjian A, Eriksen KO, Haggag M, Jaramillo AR and Terabayashi H: “Analyzing Hydrocarbons in the Borehole,” Oilfield Review 15, no. 3 (Autumn 2003): 54–61.

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Since sampling pressure was higher than the dewpoint, it was assumed the reservoir fluid was originally monophasic. However, it split into two phases when pressure decreased as it flowed to the surface. The samples were studied and recombined mathematically using a gas/liquid ratio averaged over the sampling period.

When plotted, the phase envelopes of the cap-tured multiphase sample and the bottomhole sample crossed at the sampling point, indicating the condensate and gas phases were in equilib-rium as they passed through the meter (above).

The experiment, as demonstrated by the resulting plots, confirmed several important

points for the operator: •Samples from a multiphase sampling device

are good initial material for recombination.•A gas/liquid ratio from recombination can be

used to reconstruct monophasic flow.•AnEOSworksbetterthanexperimentalrefer-

ence points.•Multiphase sampling and testing are viable

tools in formation fluid simulation.In a second study conducted in the field, a

sample from a new well was physically recom-bined using wellsite analytical equipment and thePhaseSamplerservice.Afteradayofrecondi-tioning the sample at reservoir conditions, 25 cm3 was transferred to a PVT cell for QC and saturation-pressure determination. This experi-ment resulted in a dewpoint pressure of 376.8 bar [5,463.6psi],essentiallymatchinganearlierEOSprediction of 382 bar [5,539 psi] based on math-ematical recombination.

This outcome confirmed the feasibility of using physical recombination on samples cap-tured by a multiphase sampling device. It also showed that recombination is easier to accom-plish with these samples than with those obtained using conventional means placed downstream of a separator. And finally, it demonstrated thatphysical recombination used in conjunction with bottomhole data provides essential information about flow regimes.

As a consequence of these examples andotherworkdoneoveraperiodofsixmonths,theSchlumberger and Rospan International team has developed a multiphase sampling and analy-sis program specifically for the Urengoyskoecondensate field. The procedure involves using a multiphase sampling device and an MPFM oneach well. When possible, the process includes sending one sample collected at the largest chokesettingandonecollectedat thesmallestsetting to a laboratory for testing. Each samplepair is recombined mathematically and physical recombination is provided for samples from new wells.Abotttomholesampleiscapturedineveryfifth well.

> Differences and potential error. The differences in the BOM and the PhaseSampler analysis for solution gas, oil volume factor and oil density were significant. Using the BOM would result in underestimated oil shrinkage and overestimated oil density, which could lead to significant errors in the large Berkine basin. (adapted from Bastos and Harrison, reference 13.)

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> Validation of surface samples using a bottomhole sample (BHS). This graph superimposes BHS phase envelopes and mathematically recombined samples acquired by a multiphase sampling device. Bottomhole and line conditions are shown for reference. Envelopes of the multiphase samples cross at the sampling point (green dot). The single-phase reservoir sample (SRS) was used in an EOS to obtain its phase envelope. A best-fit characterization (blue) moved the phase diagram closer to the measured dewpoint (orange triangle) and to the mathematically recombined monophasic sample (red curve) that is consistent with the BHS.

Rick_Fig06_1

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PhaseSampler gas: 11.01PhaseSampler liquid: 11.02PhaseSampler sampling conditions (6 mm)BHS: 1.02Bottomhole sampling SRSMeasured dewpointMathematically recombined PhaseSampler samples

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14. Basic sediment and water, or BS&W, refers to impurities contained in produced oil and is reported as a percentage of the fluid in samples captured at the surface. Its measurement is described in ASTM Standard Test D96-82.

15. Bastos and Harrison, reference 13.16. Oyewole AA: “Testing Conventionally Untestable

High-Flow-Rate Wells with a Dual Energy Venturi Flowmeter,” paper SPE 77406, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, September 29–October 2, 2002.

17. Theuveny B, Zinchenko IA and Shumakov Y: “Testing Gas Condensate Wells in Northern Siberia with Multiphase Flowmeters,” paper SPE 110873, presented at the SPE Annual Technical Conference and Exhibition, Anaheim, California, USA, November 11–14, 2007.

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Measuring DifferencesWhereas the flow and fluid property measure­ment challenge in the Urengoyskoe field was a product of complex geology and remoteness, in the Berkine basin of eastern Algeria, multiphase sampling was put to the test in four wells with fluid parameters that varied significantly. GOR across the wells ranged from 1,000 to 18,000 ft3/bbl [176 to 3,200 m3/m3], API gravity from 40 to 53, basic sediment and water from 0% to 33% and water salinity from fresh to over­saturated brine.14

Operators Sonatrach and Anadarko, who had formed a partnership to manage oil fields in the basin, sought to determine whether the PhaseSampler technology could accurately measure reservoir fluid properties at each wellsite. The operators required a three­step validation process:•PhaseSampler results would be compared to

BOM predictions.•PhaseSamplerandPVTmeasurementsofGOR

and gas composition would be compared.•Repeatabilitywouldbetestedbycomparingmul­

tiple flashes under identical flowing conditions.The match between PhaseSampler and labora­

tory results across the varying zones was good for

measurements of solution gas, compositional anal­ysis of free and dissolved gas and determination of gas volume and density (above). Multiphase sampling measurement repeatability was con­firmed by the performance of eight flashes each for gas and oil.

However, differences between solution gas volume, oil volume factor and oil density as calcu­lated with the BOM were significant (previous page, bottom). This confirmed experts’ early con­cerns that the BOM would underestimate oil shrinkage and overestimate oil density. Had these erroneous figures been applied to the deci­sion­making process on a reservoir the size of the one tested in the Berkine basin, the impact could have been considerable.15

The Critical PieceTraditionally, the industry has tested well flow rates and reservoir potential through the use of separators that break multiphase well effluent into its constituent phases before the measure­ment of each phase. But there have always been concerns about the quality of a separation pro­cess that uses test vessels that rely on gravity and pressure reduction. Even when results appear to

be accurate, the method has inherent flaws. Among these are carry­over, carry­under and dis­crete measurements that in complex regimes, such as slugging water, may lead to mistaken con­clusions about water cut if the readings were taken at the wrong time.16

Additionally, the type of reserves the industry is exploiting is changing. There is now increased demand for advances such as high­resolution measurements of gas/liquid ratios to determine changes in fluid properties at choke crossings. Operators are also seeking greater test repeat­ability to confirm slowly evolving trends, lower risks associated with conventional separators that capture hydrocarbons under elevated pres­sure and temperature, and high­quality data from permanent monitoring installations.17

The success of the multiphase sampling device promises to eliminate any further objec­tion to the use of MPFMs in both testing and production monitoring. Laboratory tests and comparisons with traditional sampling methods and analyses have proved its ability to collect representative fluid samples for real­time compo­sitional analysis, thus providing a critical piece to the multiphase flowmeter puzzle. —RvF

> Confirmation. Though the laboratory ambient temperature was 77°F [25°C], and wellsite temperatures ranged from 104°F [40°C] to 122°F [50°C], measurements of solution gas by both PhaseSampler analysis and the laboratory were in good agreement (top). The PhaseSampler and PVT compositional analyses for the free gas (top right ) and dissolved gas (bottom left ) were also in close agreement, as were those for the GVF and the gas density (bottom right ). Free gas and dissolved gas are represented by two bars in each graph to indicate samples measured using two different types of gas chromatographs.

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Gas

dens

ity a

t lin

e co

nditi

ons,

kg/

m3

50

40

30

20

10

80

70

60

50

40

30

20

10

PhaseSampler analysisLaboratory results

PhaseSampler analysisLaboratory results

PhaseSampler analysisLaboratory results

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