Full-scale Multiphase Flow Tests

Copyright 2003, Pipeline Simulation Interest Group This paper was prepared for presentation at the PSIG Annual Meeting held in Bern, Switzerland, 15 October 17 October 2003. This paper was selected for presentation by the PSIG Board of Directors following review of information contained in an abstract submitted by the author(s). The material, as presented, does not necessarily reflect any position of the Pipeline Simulation Interest Group, its officers, or members. Papers presented at PSIG meetings are subject to publication review by Editorial Committees of the Pipeline Simulation Interest Group. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of PSIG 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 where and by whom the paper was presented. Write Librarian, Pipeline Simulation Interest Group, P.O. Box 22625, Houston, TX 77227, U.S.A., fax 01-713-586-5955.

ABSTRACT An extensive full-scale measurement campaign has recently been carried out in one of the two 36" gas-condensate pipelines from Troll A wellhead platform in the North Sea to Kollsnes gas process plant. The main objectives of the full-scale tests were to collect data and to study the dynamics of three-phase gas-condensate-water flow in pipelines. Seven tests covering a large span of operating conditions were run measuring pressure drop and liquid accumulation in the pipeline. In addition, data on pig dynamics were collected for five of the tests. The measurement results will be used to revise operating procedures for Statoils gas-condensate transport systems and for verification and improvements of dynamic multiphase simulation codes. This paper focuses on the design and performance of the full-scale tests.

Introduction Long distance multiphase transport has become common and proven technology in Norwegian gas-condensate field developments. Recent and future developments like Huldra, Kvitebjrn, Sigyn, Mikkel and Snhvit all make use of gas-condensate transport as an essential technology element. Indeed, this has become possible due to extensive efforts to develop multiphase flow models for thermo-hydraulic calculations, such as the OLGA2000/PeTra simulations programs.

The multiphase models are particularly important in order to select the optimum pipe diameter, design temperature and defining the operational envelope with respect to minimum

and maximum flow rates. The minimum flow rate before liquid starts to accumulate considerably is an important feature, which usually limits the operational envelope for a gas-condensate pipeline. Liquid accumulation in a pipeline may cause slugging problems, and the accumulated liquid may potentially overfill the slug catcher at the receiving facility when increasing the gas flow rate. Increasing pipeline pressure loss may also be a consequence of liquid accumulation. Thus, liquid accumulation is an unwanted situation that is usually solved by draining the pipeline using scraper pigs, or simply by operating the pipeline at sufficient high flow rates to avoid the problem. Figure 1 shows typical trends of liquid accumulation and pressure loss for gas-condensate pipelines.

Furthermore, the operational limits of new subsea gas-condensate pipelines are being stretched with respect to longer transport distances and higher liquid content. An example is the Snhvit pipeline, which is planned to come into production in 2006. The wellstream from Snhvit will be transported directly in a multiphase pipeline to shore over a distance of approximately 145 km [90 miles] in harsh environments in the Barents Sea. Snhvit and similar field developments depend on reliable multiphase models for thermo-hydraulic design calculations.

The uncertainties of the multiphase flow models are incorporated in the design and field development concepts. This may, however, result in narrow operational envelopes, oversized pipelines and slug catchers, or other unsuccessfull design of the pipeline and receiving facilities. It is therefore important to improve the accuracy of multiphase models to reduce uncertainty in pipeline design and to optimise the operation of pipelines and receiving facilities. Such improvements can be achieved by exploiting operational experience from existing fields combined with systematic full-scale testing of multiphase pipelines. This means that field test measurements can be a basis for potentially increased flow capacity, larger operational envelope and less operational problems (e.g. slugging) of existing and new pipelines.

Based on the above considerations it was deceided to design and carry out a comprehensive full-scale measurement campaign in a 36" and 67 km [41.6 miles] long gas-condensate pipeline from the offshore Troll field to shore at Kollsnes.

PSIG 03B1

Full-scale multiphase flow tests in the Troll pipelines Ronny Albrechtsen, Statoil, Natural Gas, Krst, Norway Elling Sletfjerding, Statoil, Research & Technology, Trondheim, Norway

2 RONNY ALBRECHTSEN, ELLING SLETFJERDING PSIG 03B1

THE TROLL FIELD The Troll field is located west of Bergen in the North Sea and contains 60 per cent of Norways proven gas reserves. The production started in June 1996 and the maximum production capacity is about 100 MSm3/d [3532 MSCF/d], or 30 GSm3/year [1060 GSCF/year].

The Troll field comprises the two main structures Troll East (Phase I) and Troll West (Phase II). The gas province in the East structure is being produced by the Troll A concrete platform, which exports the gas through two wet gas pipelines to the onshore gas treatment plant at Kollsnes near Bergen, see schematic overview in Figure 2. The thin oil layers in the Troll West structure are produced by the Troll B & C platforms, where the separated oil is is transported in two pipelines to the Mongstad refinery. The part of the associated gas from the West structure which is not re-injected is transported in two 16" pipelines to Troll A, as indicated in Figure 2. Statoil operates Troll A, Kollsnes process plant and the wet gas pipelines, while Norsk Hydro operates Troll B & C.

Troll A is a wellhead platform producing from 38 gas wells at depths of approximately 1400 m [4590 ft]. Gas conditioning and processing are limited on the platform. The producing wells are routed into four parallel inlet separators, where the free water is removed. The gas and condensate phases are remixed and co-mingled with rich gas from Troll B & C before entering two parallel transport pipelines (P10 & P11) to shore. Approximately 90 % lean MEG (Mono Ethylen Glycol) is injected into P10 and P11 at Troll A for hydrate inhibition and corrosion prevention. Figure 2 gives a schematic overview of the transport system from Troll to Kollsnes.

The two 36" pipelines (P10 & P11) transfer multiphase flow of gas, condensate and glycol/water over a distance of 67 km [41.6 miles], where each line is design for 50 MSm3/d [1766 MSCF/d]. Figure 3 shows the elevation profile of the two pipelines, where maximum water depth is about 350 m [1150 ft]. The seabed is almost flat except the last part which is very hilly and the pipelines have therefore been laid in a tunnel the last hill towards the outlet, as indicated in Figure 3. The pipelines are not insulated, and due to cooling by seawater and pressure loss in the pipeline, free water and condensate drop out from the gas phase, forming a a three-phase mixture of gas, condensate and aqueous glycol.

At the tunnel outlet at Kollsnes, the wet gas pipelines are directed into two dual slope bottle type slug catchers where the initial separation takes place. The maximum capacity of the slug catchers is 2500 m3 [88300 ft3]. The total liquid gas ratio at the pipeline outlet is approximately 23 m3 liquid per million Sm3, or 4.1 bbl/MSCF.

The gas from the slug catchers is then further processed in a dew point control system before being exported to UK and the continental Europe via the gas network system in the North

Sea. The stabilized condensate is exported to Mongstad refinery in a separate pipeline. The Kollsnes process plant is currently being expanded with an NGL process system in order to extract the liquid components from new gas field developments (Kvitebjrn and Visund) by 01.10.2004.

Design and implementation of the field tests The main ambition with the measurement program was to measure liquid accumulation in the pipeline at a wide range of flow rates. Basically, the tests were conducted by running the pipeline at predefined and constant inlet flow rates until stabilized conditions in the pipeline were reached, whereafter a cleaning pig was sent in order to drain the accumulated liquid into the slug catchers. The liquid slug was then measured by the liquid level measurement system on the slug catchers. In addition, the velocity and volume of the liquid slug in the pipeline P10 was measured by gamma densitometers located temporarily on the outlet pipeline.

From earlier measurements in the P10 pipeline it was expected that liquid accumulation would increase rapidly for flow rates below 70 % of design rate. Thus the test programme was designed to cover the flow rate range from 90-50 % of design rate, with special focus on the range from 70-50 % (cf. test program in Table 1). All tests were planned to run with an outlet pressure of approximately 90 bar [1305 psi].

It was decided that liquid accumulation should be measured by pigging the pipeline in order to get a more accurate measure of accumulated liquid than may be achieved by dynamic pigging (i.e. flow rate increase). All tests at flow rates of 80 % of design rate and lower were planned with pigging. The test at 90 % of design rate was planned to run without pigging as a pressure drop test. Sending a pig at the end of each test had two purposes; liquid drainage and measuring pig dynamics and temperature profile along the pipeline route.

Normally, in gas-condensate pipelines, the condensate drops out and accumulates first, and then the water will accumulate over time before a full stabilization of the pipelines is reached. It was apparent that it would not be possible to run the pipeline to fully stabilized conditions at low flow rates due to the capacity of the slug catchers. Therefore, all tests were planned to run for a limited time of about 48 hours before pigging. It was expected that all tests would reach stabilized conditions within the 48 hours, except for test 7 which was planned as a transient test.

The test program (Table 1) was planned and accomplished during the summer season 2002 without interfering the gas export from Kollsnes. The gas export is governed by the demand in continental Europe, and in the winter season the gas demand is normally too high to match the planned test flow rates. Thus, the test period was chosen to be in the

PSIG 03B1 Full-scale multiphase flow tests in the Troll pipelines 3

summer season when the gas export is more likely to fit the test rates. Moreover, the flexibility of the two pipelines P10 and P11 offers a unique possibility of keeping constant flow rate in one pipeline (P10), and let the other pipeline (P11) take care of the variations in the gas export. However, it was not possible to maintain constant flow rate in P10 when large changes in the export rate was required within the test period. In such cases the tests had to be terminated and restarted when the gas export was more favourable.

INSTRUMENTATION AND DATA ACQUISITION

Measurement and data acquisiton

Existing process instrumentation on Troll A, B & C platforms, as well as on Kollsnes process plant, was used as a basis for the field test measurements. However, additional instruments were needed for measurements of flow details. For this purpose, three gamma densitometers were installed temporarily during the tests on the outlet of pipeline P10.

A built-in sampling and acquisition program in the PCDA system was configured to acquire and store predefined instruments when started from the control room. The sampling frequency of each instrument was predefined to be 1/30 Hz (twice a minute) or 4 Hz. Gamma densitometers and outlet pressure transmitters were sampled at 4 Hz.

A large number of different measurement signals were acquired during each tests. The most important instruments and measurement systems are briefly described in the next sub-sections. Vital instruments were checked and/or calibrated prior to the test program in order to obtain high quality and reliable measurement data with low uncertainty.

Flow rate measurements

Flow rate measurements were mainly based on the existing metering systems on the platforms and at Kollsnes. On the pipeline inlet the following flow rates were measured:

Gas flow rate from Troll A in P10 and in P11 Gas flow rate from Troll B in either P10 or P11 Gas flow rate from Troll C in either P10 or P11 MEG injection flow rate in P10 and P11 Condensate flow rate in P10 (temporary during the tests) The gas flow rates from Troll A were measured using orifice meters with pressure and temperature compensation, but with a constant composition. Qualified personnel calibrated the pressure and temperature transmitters used in connection with

the orifice meters at Troll A. The gas flow rates from Troll B & C are measured at fiscal standards (uncertainty less than 1 % in mass flow). This included measurements of pressure, temperature and compositional analysis in addition to flow rate (orifice meters) on Troll B & C platforms. The flow rate from Troll A into P10 and P11 together with the fiscal measurements of Troll B and C gas flow rates were used to determine the total gas rates into each of the two pipelines.

The two orifice meters used for condensate injection were defect, and a clamp-on ultrasonic flow meter was therefore installed temporarily on the condensate injection line. This made it possible to measure the P10 inlet condensate flow rate during the tests.

At the pipeline outlet at Kollsnes, the following flow rates were measured:

MEG/water drainage rate from the slug catchers Condensate drainage rate from the slug catchers Fiscal measurements of gas and condensate export Flare gas The fiscal measurements of Kollsnes export are subject to regular calibration and verification according to governmental requirements. During stable periods, the total gas flow rate into the pipelines was found to be very close to the fiscal measurements at Kollsnes. The measurement of the inlet gas flow rate to P10 and P11 were therefore regarded to be accurate within 1 - 2 per cent.

The drainage rates from the slug catchers were measuered by high quality ultrasonic meters. These measurements were important to determine the outflow from the slug catchers during the tests.

Pressure and temperature transmitters

The pressure and temperature measurements are based on existing transmitters offshore (Troll A, B & C) and onshore (Kollsnes). Vital transmitters for the tests, i.e. inlet and outlet pressure and temperature gauges, were calibrated by qualified personnel. The accuracy of these instruments was documented to be within 0.5 bar [ 7.3 psi] and 0.5 C [ 0.9 F] for pressure and temperature transmitters, respectively.

Liquid level measurements in slug catchers

The original liquid level measurement system installed on the slug catchers is based on differential pressure (DP) cells, which measure the pressure head of a fluid column and convert it to a fluid level when the fluid density is known. This system has not been reliable, and large fluctuations have been experienced. This is mainly because the measurement system


is based on ideal phase separation. Blocking of the pressure taps may also give erroneous results.

Four gamma densitometers (137Cs) have been installed permanently on the two slug catchers in order to measure the condensate and aqueous glycol levels. These instruments are more reliable and accurate than DP since the density is directly measured by attenuation of gamma ray beams irrespective of fluid phase mixing and non-ideal separation. Unfortunately, the gamma densitometers only cover part of the full level range in the slug catchers. It was therefore deceided to install three temporary gamma densitometers on the P10 pipeline for accurate liquid plug measurements (see next sub-section).

Liquid slug measurements using -densitometers Two single beam gamma densitometers (137Cs) were installed approximately 100 m [328 ft] apart from each other on a horizontal straight section upstream the slug catchers. These two instruments were used for measurement of velocity and volume of liquid slugs, as well as indicating unsteady liquid flow, produced when pigging the pipeline (see Data analysis). A third gamma densitometer was installed on a 30" pipe section close to, but upstream the slug catchers at Kollsens. This instrument was specially designed for accurate density measurement and to estimate condensate and glycol fractions.

Pig measurements using data logger

A scraper pig was launched and sent through the P10 pipeline at the end of each liquid accumulation test (test 2 - 7) in order to shove the accumulated liquid in front of the pig and into the slug catchers. A data logger installed in the pig was used to measure temperature, pressure, differential pressure and acceleration along three axes. In addition, two odometer wheels were installed to record the travelled distance and thereby the pig velocity. The sampling frequency used for the tests was 5 Hz.

Gas chromatography (GC) analysis

In order to characterize the fluid properties the gas composition is needed. Gas sampling and compositional analysis is performed and reported regularly at fiscal standards once a week on Troll B & C platforms. There is no regular sampling and analysis of the Troll A well stream. The available compositions of Troll A well stream was therefore based on statistical average of previous well samples. Fiscal online sampling and GC analysis is performed continuously on the export gas (sales gas) from Kollsnes.

The transported gas through the pipeline is a mixture of gas from Troll A, B and C, and the average based on flow rate from each field was used to characterize the fluid properties for each test. Troll A gas dominates with 75-100 % contribution into the pipelines P10 & P11, while Troll B and/or Troll C contribute with the rest.

DATA ANALYSIS Measured and acquired data from each test were sorted and stored systematically for further processing and analysis. The averages of pressure, temperature and flow rate measurements were computed from selected stable periods. Other parameters, such as liquid slug velocity, pig velocity and liquid volume arriving at Kollsnes during pigging, needed special evaluation and analysis methods. These methods are described in the next sub-sections.

Particular attention was given to estimate the liquid volumes arriving at Kollsnes, and three independent methods were therefore employed to measure the liquid volumes. The three methods predict the volume of condensate and aqueous glycol (MEG/water) based on measuring:

Liquid levels in slug catchers using differential pressure (DP) transmitters.

Liquid levels in slug catchers using gamma densitometers. Liquid plug velocity and density using gamma

densitometers on test pipeline P10.

It is important to note that the three methods only predict the volume of the liquid plug ahead of the pig. Any thin liquid film flowing in the pipe is not included in the volume measurements, although some of the density readings indicate a wavy film ahead of the liquid plug. Moreover, any liquid leakage across the pig is neither included in the measurements.

Liquid levels and slug catcher volumes

The measured liquid levels in the two slug catchers are converted to corresponding volumes by using calibrated level volume curves. The volumes of condensate and aqueous glycol entering the slug catchers were determined by measuring the volume difference before and after arrival of the liquid slug. The measured volumes were corrected for the drained condensate and aqueous glycol volumes during this period.

Figure 4 shows an example from test 4, where the condensate level increases sharply when the liquid plug enters the slug catcher at approximately 3 hr. and 40 min after launching the pig. The very high condensate levels measured by the DP transmitters are unphysical and are caused by the chaotic and turbulent process in the slug catchers with no sharp fluid interface between gas and condensate. The gamma densitometers give more realistic measurements during this phase, since they measures the true density of the mixture. However, as the separation process takes place in the slug catchers and the fluid phases separates, the differential pressure transmitters are approaching the correct condensate level. The duration of the separation process depends on the amount of liquid entering the slug catchers, but it takes


normally 30 40 minutes. The pigged condensate volume is determined from the difference of the volume when the fluid phases have stabilized and the volume before pig arrival.

The pigged aqueous glycol volume is determined from the volume difference between the same time periods as was used for prediction of the condensate volume, see Figure 4. The aqueous glycol level increases smoothly towards a stable level and no sharp volume increase is observed. This is probably because a distinct interface is maintained between the aqueous glycol and condensate phases, since the aqueous phase is slowly sinking through the condensate phase and there is low turbulence in the lower part of the slug catchers.

Liquid plug measurements

The two densitometers located approximately 100 m [328 ft] apart at the pipeline outlet at Kollsnes were used to calculate pig velocity, liquid plug front velocity and the liquid plug volume. Figure 5 shows a schematic of the measurement setup. Density discontinuities such as the liquid plug front and the pig are detected by the densitometers with a time difference, which is correlated to give slug front and pig velocities. Combining the measured liquid slug duration with the velocity distribution of the pig then yields the liquid plug volume. Furthermore, a third gamma densitometer with a stronger radiation source was used for accurate density measurements of the multiphase mixture on a 30" pipe section downstream the other two densitometers This density measurement was used to determine the fraction of aqueous glycol and condensate in the liquid plug.

Typical time traces from the densitometers are shown in Figure 6. The arrival of the liquid plug is seen as the sharp increase in measured density in the readings from the three densitometers. The pig arrival is seen in Figure 6 as a sharp reduction in density as the pig passes the densitometers and the measured density is that of the gas behind the pig. Note that all three densitometers are only calibrated at gas filled conditions in the pipe, and that the two first densitometers are not capable of measuring the correct density in the liquid plug due to the large pipe diameter, i.e. they are only used for slug detection. The third densitometer on the smaller 30" pipe is used for accurate density measurements.

The liquid plug front velocity and the pig velocity are calculated based on the time lag, t, of the front and pig arrival between the two gamma densitometers placed approximately 100 m [328 ft] apart. The liquid plug duration is found directly as the time lag between the arrival of the liquid plug front and the pig. Note that the liquid plug duration is not identical for the three densitometers due to plug acceleration.

Test results All test were run successfully according to the plan (Table 1), except for Test 2 where the data logger in the pig was not available. However, the pig was run without the data logger in Test 2 to measure the liquid accumulation as planned.

Trend measurements

Stable periods were selected for each test in order to define a main test period lasting approximately 48 hours and a second test period being at the very end of the test period. The second test period is used to determine the pressure loss in the pipeline, while the general trends are used for further analysis.

The main trends from Test 3 are presented here in Figure 7 through Figure 11 as examples from one of the seven tests. The predefined test rate was 70 % of design rate for approximately 48 hours before pigging, see Figure 7. Gas from Troll A and Troll B was produced into P10 during the test (no gas from Troll C). Figure 7 show that the flow rate in the test pipeline P10 is stable, while the flow rate in the other pipeline varies according to the gas export demand.

The injection of MEG is automatically controlled by the measured gas flow rate and the injection rate is fairly constant when the gas flow rate is stable, as can be inferred from Figure 7. The large fluctuations in the condensate injection rate (Figure 7) are mainly due to pressure driven drainage of the separators that causes a highly irregular injection rate.

Pressure loss measurements (Figure 8) and outlet temperature measurements (Figure 9) show that the pipeline is well stabilized before the pig is run in the pipeline.

When the pig starts to enter the landfall zone (about 59-60 hrs), the slug catcher pressure (outlet pressure) starts to decrease (Figure 10). The slug catcher pressure is allowed to vary freely to compensate for the static pressure of the liquid plug in front of the pig. These pressure oscillations reflect the pipeline profile and the amount of liquid in the plug. The arrival of the liquid slug is seen in Figure 10, as the density suddenly rises to the liquid value, and falls down to the gas density value when the pig has passed by the densitometer.

The pig velocity recorded by the data logger in the pig is shown in Figure 11. The peak velocities coincide very well with the topographic peaks near the landfall zone. The pig velocity reaches minima at the bottom of the hills due to slow down by accumulated liquid in lower points. The pressure behind the pig and the static liquid head of the slug governs the uphill motion of the pig. I.e., the pig accelerates towards the top of the hill because of increasing difference between the driving pressure behind the pig and the static liquid head when the liquid passes over the top of the hill. This is clearly seen in the last hill (tunnel) towards Kollsnes (Figure 11), and the effect was even more pronounced for longer liquid plugs.


Pressure loss

The pressure loss in the P10 pipeline is computed as the difference between the inlet and outlet pressure measurements at the end of the test periods. Figure 12 shows the measured pressure loss versus gas flow rate for tests carried out in 2002 and previously recorded operational data. The 2002 results are in good agreement with the previous measurements.

At high gas flow rates (i.e. beyond 70 % of design rate) only a small amount of liquid is in the pipeline and steady state conditions are established quickly. At steady state, the liquid outlet rate equals the liquid input plus the condensed liquid in the pipeline due to pressure loss and temperature decrease. At these high gas flow rates the pressure loss is dominated by the gas velocity, and the pipe flow is nearly equivalent to single-phase gas flow, and the pressure loss is friction dominated (Figure 12). When the gas flow rate decreases below approximately 70 %, it can be inferred from Figure 12 that the pressure loss curve flattens, which is due to accumulation of liquid in the pipeline because of lower gas velocity. The increasing amount of liquid in the pipeline as the flow rate decreases tend to shift the pressure loss mechanism from friction towards gravity dominated. However, the measured pressure loss does not become fully gravity dominated, since the pressure loss measurements do not increase as the flow rate decreases.

Accumulated liquid volumes

Measurements of liquid volumes were based on three different measurement principles (as previously described) and the mean values were computed. However, in some of the tests, one or two of the measurements of liquid volumes were excluded from the analysis because the measurements were out of range or obviously incorrect.

The volumes measured are the volumes of the liquid plug that was formed in front of the pig. To estimate the total liquid inventory of the pipeline, the amount of liquids produced out of the pipeline during pigging is added to the measured plug volume. The volumes of the liquids produced during pigging are estimated based on typical gas liquid ratios.

Figure 13 shows the mean values of the total liquid content (aqueous glycol and condensate) in the pipeline for the different tests. Liquid volume is expressed as per cent of slug catcher capacity, and there is no danger to overfill the slug catcher at these flow conditions. Previous tests from 1996 and 1997 are also included in the diagram for comparision. The previous measurements indicate considerable more liquid than the 2002 test results. Liquid accumulation measurements show that the pipeline is "drier" than expected, i.e. it indicates lighter gas composition.

Generally, the measured liquid volumes show that the liquid accumulation increases gradually at flow rates from 70 to 55

% of design rate. Then a much sharper increase in liquid accumulation is experienced between 55 and 50 % of design rate. At flow rates as low as 55 %, the flow in the pipeline is still not solely gravity dominated. Frictional forces between gas and liquid still ensure a relatively effective liquid transport at this flow rate. All tests, except the test at the lowest flow rate were found to be fully stabilized before pigging.

CONCLUSIONS A comprehensive measurement program has been designed and conducted successfully in the Troll-Kollsnes P10 gas-condensate pipeline. The planned test program, including measurements of liquid accumulation, pressure drop and pig velocity, was completed due to valuable contributions from personnel from various resource units in Statoil.

The test program comprised seven main tests. Each test lasted for about 48 hours and was carefully planned and performed without interferring the field production and gas transport. Measurement data from a large number of instruments were acquired and stored for each test using a dedicated logging program. Existing process instrumentation onshore and offshore were used as a basis for the field test measurements. It was, however, necessary to use additional instruments dedicated for detailed flow measurements, such as velocity and volume of liquid slugs. For this purpose, three gamma densitometers were designed and installed temporarily on the outlet of the test pipeline. This enables accurate measurement of liquid slugs in the pipeline and is of great importance in such field tests.

The measurement results will be used for verification and improving dynamic multiphase simulation codes, such as OLGA2000 and PeTra. Full-scale field data are inevitable valuable to strengthen and improve multiphase flow simulation programs. Furthermore, the measurement results and the experience gained from the tests will be used to revise and improve operating procedures for Troll-Kollsnes and other gas-condensate transport systems operated by Statoil. Generally, the experience and knowledge gained from systematic field test measurements are of great importance for design and operation of new and existing pipeline systems.

ACKNOWLEDGEMENTS The authors ackowledge the Troll license with the partners Statoil, Petoro, Norsk Hydro, Shell, TotalFinaElf and Conoco for permission to publish this paper. The co-funding of the field tests from Gassco is also appreciated. Valuable contributions from the operational personnel on Troll A and Kollsnes during planning and execution of the tests are greatfully appreciated.


TABLES

Test No. Flow rate [% design rate]

Outlet pressure [bar / psi]

Pigging Test duration [hrs]

Test period

1 90 90 / 1305 No 26 06-07 July 02

2 80 90 / 1305 Yes 55 02-05 July 02

3 70 90 / 1305 Yes 50 08-11 July 02

4 65 90 / 1305 Yes 52 21-23 Aug 02

5 60 90 / 1305 Yes 48 11-14 July 02

6 0.55 90 / 1305 Yes 54 02-04 Sept 02

7 50 90 / 1305 Yes 53 12-14 Aug 02

Table 1 Overview of planned and performed test program in the P10 pipeline. Test 1 was a high rate pressure loss test. Test 2 7 were liquid accumulation tests. Design flow rate is 50 MSm3/d [1766 MSCF/d].

FIGURES

0

50

100

150

200

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350

0 25 50 75 100 125 150Gas flow rate

Liqu

id v

olum

e

75

95

115

135

155

175

195

Pre

ssur

e lo

ss

Liquid accumulationPressure loss

Figure 1 Typical liquid accumulation and pressure loss trends for wet gas pipeline transport. At high gas rate the liquid is effectively transported out of the pipeline and it is only small amount of liquid in the pipeline. The pressure loss is frictional dominated and similar to the single-phase gas pressure loss. Liquid accumulation increases dramatically when the gas flow

rate decreases below a minimum value. The pressure loss mechanism becomes gravity dominated and increases as the liquid content increases in the pipeline.


Glycol regeneration

P10

P11

Gas

Condensate

MEG/water

Slug catcher 1

Slug catcher 2

Troll A

Troll B

Troll CFree waterGlycol regeneration

P10

P11

Gas

Condensate

MEG/water

Slug catcher 1

Slug catcher 2

Troll A

Troll B

Troll CFree water

Figure 2 Schematic of the wet gas transport from the Troll platforms to Kollsnes. Free water and condensate are separated at wellhead conditions on Troll A, where the water is removed and condensate is re-injected into the gas stream. Rich gas in dense phase from Troll B and C are mixed with the Troll A gas on the Troll A platform upstream the inlet of P10 and P11.

Glycol (approx. 90 % lean MEG) is injected at Troll A, and after separation in the slug catcher at Kollsnes the glycol is regenerated and transported back to Troll A in a separate 4" pipeline (not shown in the figure).

Troll A - Kollsnes pipeline profile

-1

-0.8

-0.6

-0.4

-0.2

0

0.2

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Scaled distance (l/L)

Scal

ed e

leva

tion

(h/H

)

Tunnel inlet

Troll ATunnel outlet(Kollsnes)

Figure 3 Pipeline elevation profile for P10/P11 between Troll A and Kollsnes. The distance from Troll A is scaled by the total

pipe length L = 67 km [41.6 miles] and the elevation is scaled by the maximum water depth H = -350 m [1150 ft].

Kollsnes


0 10 20 30 40 50 60 70 80 90 1000

0.1

0.2

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0.8

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time [min], starttime 3 h after pig launch

Test 4 detail: Condensate volume in slug catcher

Cond

ensa

te v

olum

e []

Slug catcher A dPSlug catcher B dPSlug catcher A gammaSlug catcher B gamma

0 10 20 30 40 50 60 70 80 90 1000.2

0.3

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Test 4 detail: Glycol volume in slug catcher

Glyc

ol v

olum

e []

Slug catcher A dPSlug catcher B dPSlug catcher A gammaSlug catcher B gamma

Figure 4 Example of condensate (left) and aqueous glycol (right) volume measurements when a liquid plug enters the slug catchers during pigging of the P10 pipeline. The y-axes are scaled with the maximum volume of condensate

(left) and glycol (right), 1000 m3 [35320 ft3] and 250 m3 [8830 ft3] respectively.

v

L

v

L

Figure 5 Measurement setup for liquid plug measurements in the test pipeline P10. The setup comprises two gamma densitometers placed a distance L apart.

30 32 34 36 38 40 42 440

0.2

0.4

0.6

0.8

1

Test 4 gamma densitometers


dens

ity (r

elativ

e wate

r den

sity)

[]

Gamma4Gamma3Gamma1

Figure 6 Example of density measurements when a liquid plug and pig passes the two densitometers (gamma4 and gamma3)

located approx. 100 m [328 ft] apart and the readings from the densitometer (gamma1) placed downstream the two others.


0 10 20 30 40 500

0.2

0.4

0.6

0.8

1Test 3: Gas flow rates in P10 and P11

Gas

flow

rate

[%]

PIG in pipelineP10P11

0 10 20 30 40 500

0.2

0.4

0.6

0.8

1

time [hours], starttime 08.07.02 16:00:08

Test 3: MEG and condensate injection rates P10

Injec

tion r

ate [

]

MEGCondensate

Figure 7 Flow rate and injection rate measurements during Test 3. Y-axis scaled with design rate (top figure) and

10 m3/h [353.2 ft3/h] (bottom figure).

0 10 20 30 40 500.8

0.85

0.9

0.95

1

1.05

1.1

Pres

sure

[]

Test 3: Inlet and outlet pressures P10

PIG in pipeline

Inlet pressure P10Outlet pressure P10

0 10 20 30 40 500.05

0.1

0.15

0.2


Pres

sure

dro

p []

Test 3: Pressure drop P10

Pressure drop P10

Figure 8 Pressure measurements during Test 3. Both Y-axes are scaled with mean inlet pressure.


0 10 20 30 40 500

10

20

30

40

50

60

70Test 3: Temperatures

Tem

pera

ture

[C]

PIG in pipeline

Troll A inlet P10Troll B inlet P10

0 10 20 30 40 5032

68

104

140

Tem

pera

ture

[F]

0 10 20 30 40 500

5

10

15


Tem

pera

ture

[C]

Kollsnes outlet P10

0 10 20 30 40 5032

41

50

59

Tem

pera

ture

[F]

Figure 9 Temperature measurements during Test 3.

52.5 53 53.5 54 54.5 550.97

0.98

0.99

1

1.01

1.02

1.03Test 3: Outlet Pressure during pigging P10

Pres

sure

[]

P10 outlet pressure

52.5 53 53.5 54 54.5 550

0.2

0.4

0.6

0.8

1Test 3: Measured density outlet P10

Den

sity

(rela

tive w

ater)

[]

time [hours],starttime 08.07.02 16:00:08

Density outlet P10

Figure 10 Outlet pressure and density measurements during pigging of Test 3. Y-axis on top figure is scaled with the mean

outlet pressure.


0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10

0.2

0.4

0.6

0.8

1Test 3: Measured PIG velocity

Pig

velo

city

[]

Pig Velocity

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 11

0.8

0.6

0.4

0.2

0

Pipeline length []

Elev

atio

n []

Test 3: Pipeline profile

Pipeline profile

Figure 11 Measured pig velocity and pipeline profile during Test 3. Pig velocity (top figure) is scaled with the maximum

velocity, the elevation profile is scaled with the maximum depth and the total pipe length (cf. Figure 3).

Pressure loss in P10

0

0.05

0.1

0.15

0.2

0.25

40 50 60 70 80 90 100

Gas flow rate [% of design rate]

Rel

ativ

e pr

essu

re lo

ss

Single-phase predictionTests 2002Previous operational data

Figure 12 Relative pressure loss versus gas flow rate in the P10 pipeline. The pressure loss is relative to the inlet pressure. The single-phase prediction is based on isothermal gas equation using average gas properties and total

mass flow rate of gas and liquid.


Troll field tests - Total liquid volume in pipeline

0

10

20

30

40

50

60

45 50 55 60 65 70 75 80

Gas flow rate [% of design rate]

Liqu

id v

olum

e [%

of s

lug

catc

her c

apac

ity] Tests 2002

Test 1997

Test 1996

Figure 13 Total liquid content in the pipeline P10. The amount of liquids produced out of the pipeline during

pigging has been added to the measured plug volume

Appendix A Biographies Ronny Albrechtsen received a M.Sc. degree in Petroleum Engineering from Stavanger College (Norway) in 1990. He has worked seven years at different technical colleges and universities with lecturing and fundamental research on measurement and analysis of multiphase flow in pipes, and was awarded a PhD on this subject by Aalborg University (Denmark) in 1998. After 3 years as Program Manager within process metering at Christian Michelsen Research he joined STATOIL ASA in 2001 and works with optimisation and analysis of gas transport. Albrechtsen is now Sr. Discipline Adviser within gas transport analysis.

Elling Sletfjerding is Staff Engineer in STATOIL ASA. Sletfjerding received his Doctoral degree from the Department of Petroleum Engineering and Applied Geophysics at the Norwegian University of Science and Technology (NTNU) in Trondheim (Norway) in 1999 and his Master of Science degree in Applied Mechanics from the Royal Institute of Technology in Stockholm (Sweden) in 1994. Sletfjerding has been involved in research and development for 8 years working primarily with single phase gas flow in pipelines, multiphase flow and flow assurance.

Full-scale Multiphase Flow Tests

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