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HIGH GAS MPFM AN OPERATOR’S EXPERIENCE

Wisnu Purwanto, Brunei Shell Petroleum Company Sdn. Bhd.

1 INTRODUCTION Brunei Shell Petroleum (BSP) Co. Sdn. Bhd.’s activity is primarily exploring and producing crude oil and natural gas from onshore and offshore fields. Today, 90 percent of its oil and all its commercial gas come from seven offshore fields north of Borneo. This paper looks into design and operational aspects of High Gas Multiphase Flow Meter (HG-MPFM); BSP went through when developing two new oil-and gas fields’ offshore Brunei. The two fields Champion West (CWDP01) and Egret (EGDP01) are special from a metering point of view. The CWDP01 initially produces oil, and then further developed to produce gas; whereas the EGDP01 produces gas in the early stage then developed to produce oil. In both cases, oil and gas fields are commingled into the same well testing facility. In addition to elaborations around the special design criteria’s, the paper also explores the dynamic flow tests and the meter commissioning undertaken in project phases. From there it goes into detailing the operating phase in an attempt to highlight meter performance towards well behavior. 2 THE APPLICATION 2.1 Champion West Drilling Platform 01 - CWDP01 The Champion West Field is situated approximately 90 km offshore from Seria, 7 km N-NW of the Champion Main field and some 15km NE of the Iron Duke field. Water depth in the area is around 40 to 55 m. Champion West is developed as a “Smart field”, i.e. a fully integrated, remote controlled and operated field. Both down hole and surface pressure, temperature, fluid and flow data will be continuously gathered and immediately transmitted to end users for on line monitoring and control. Production allocation will be automatic and the data flow will be linked to well, reservoir and production models to ensure optimal well off take and reservoir management strategies are adopted. The CWDP01 (Champion West Drilling Platform) – perhaps one of the world’s most advanced smart field platforms; is a new remotely controlled 20 slots drilling platform; designed and constructed as part of phase 3 Champion West Development project. The project had been planning to drill 11 oil wells (5 snake wells and 6 conductor connector wells) and 9 gas wells.

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Figure 1 Sea view of CWDP01

The oil wells typically operate in HP mode with GVF (Gas Volume Fraction) 40 – 60%. The gas wells with GVF up to 99% will be operated in HHP mode. Consequently, the well test facilities on CWDP01 should be designed to handle 0 – 100% GVF, 0 – 100% water cut and suitable for well testing both HP oil wells and HHP gas wells.

HP oilmanifold

HHPgas

manifold

DrainSump

LCFI

Corrosion

Inhibitor

Tank

Vent

Header

Deck drain

Vent

KOD

KOD

pump

CI

pump

Multiphase

Meter

Gas/Condensate

To

CPCB-7 (V-711)

Hydrate

Inhibitor

Tank

TEG

pump

NAG WELLS

(9 offs)

OIL

WELLS

(11 offs)

Multiphase oil

To

CP-7 (V-730)

36 Meter Vent

Boom

DN 300 CS

600#

DN 300

600#

DN 150

600#

testmanifold

DN 250

150#

DN150 DSS

600#

DN150 DSS

10000#

DN150 CS

2500#

DN150 CS

600#

CWDP-1 PFS

Purge

Figure 2 CWDP01 Process Flow Scheme

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In October 2005, the first High Gas MPFM for Brunei Shell Petroleum was completely installed at the CWDP01. The first oil was produced by CW-29 on December 2005 and then followed by CW-28 in January 2006. The first gas from the nine (9) Gas wells with GVF up to 99% is expected to come on stream by early 2007. 2.2 Egret Drilling Platform 01 - EGDP01 The Egret project was developed in two phases. Phase 1 was executed in 2003 and Phase 2 came on stream in 2006. The Egret phase 1 is a gas development project with its primary objective being to develop some HHP gas to honor market demand. The EGDP01 (Egret Drilling Platform) comprises of 12 slots and 12 well strings were constructed in 2003 as part of the Egret field development Project Phase 1. Similarly as the CWDP01, each gas flow line has a dedicated wet gas venturi meter. Phase 2 is mainly an oil development project, along with the development of remaining gas from the Eastern flank. This development helps further sustaining BSP’s gas and oil production. With the introduction of oil wells, combined with a need to improve well allocation measurement; a dedicated well testing facility was required for oil wells and gas wells on EGDP01. 2.3 The Challenge The above mentioned flow production profiles combined with foot print restrictions posed a design challenge to the CWDP01 and EGDP01 project teams what well testing availability concerned. Conventionally, measurement of production fluids requires complete gas/liquid separation using a test separator. The separated fluids then will be measured independently using well-known single phase measurement devices; such as:

• Orifice meter, V-Cone, or Vortex for the separated gas,

• PD meter, Turbine meter or Coriolis meter for liquid measurement,

• Water Cut Meter for water in oil content measurement. Liquid carry over into the gas stream and gas carry under into the liquid stream will however affect these measurements since the above devices are not designed for multiphase measurement. As example, the liquid can cause gas flow rate over-readings when using orifice plates as the differential pressure increases with the amount of liquid in the stream. For liquid measurement, gas breakout and cavitations may occur before, or in the meter due to the pressure drop. This will deteriorate the measurement uncertainty, or even worse – may inflict damage to the equipment. The system measurement uncertainty of test separators can be in the order of 10% relative for each phase, provided all equipment and instrument are working properly. Having performed a comprehensive and comparative study; the project decided to install a non-conventional Multi-phase flow meter (MPFM) for remote (unmanned) testing of all wells as it supposedly offers:

• Better measurement uncertainty, reliability, and repeatability over time

• Expected to be Lower CAPEX & OPEX

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• Smaller footprint occupies less platform space

• On-line, real-time measurements.

• Faster set-up time, less testing time and higher well tests frequency resulting in more accurate information.

3 DESIGN AND PROJECT PHASE 3.1 Design criteria Both HG-MPFM for EGDP01 and CWDP01 needed a design catering to the following requirements: 3.1.1. Process requirements: Liquid flow rate : 30 – 2,000 m3/d, Gas flow rate : Maximum 2,000,000 sm3/d @ 6500 kPa GVF : 0 – 100% Water cut : 0 – 100% Operating Pressure : 2500 – 8250 kPag Operating Temperature : 50 – 85 C Piping Class : ANSI 600 lb Max. Pressure Drop : 200 kPa

3.1.2. Uncertainty budget

Table 1 Uncertainty Budget

Uncertainty

GVF Range (%)

Gas

(% Relative)

Liquid

(% Relative)

Water Liquid Ratio (%

Absolute)

0 - 30 10 2.5 2

30 - 90 3.5 2.5

90 - 96 6.5 3.5

96 – 99 8 5.5

99 - 100

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3.1.3. HG MPFM system configurations – The deliverables To achieve the above requirement, the system were designed, engineered and fabricated as a stand-alone skid mounted package as follows:

• DN 150 ANSI 600 Lb rating inlet / outlet header – Duplex stainless steel material

• A GDS cyclone separator, Duplex stainless steel material with a single multiphase flow inlet connection and two outlet connections (one for gas and one for conditioned multiphase flow) providing partial separation in a very compact vessel. A Differential Pressure transmitter is installed between the liquid and gas outlets of the cyclone separator to detect excessive liquid level.

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• A 2” Roxar Multiphase Flow Meter MPFM 1900 VI, DN50 with beta ratio 0.7 for EGDP01 and 0.6 for CWDP01 – Duplex Stainless steel material.

• A Coriolis meter, to measure the separated gas flow rate and also to provide detection of liquid carry over by measuring excitation signal voltage.

• Two control valves, one for the gas leg and one for the liquid leg. The valves are DN100 - Duplex Stainless steel material.

• A cabinet to house the High Gas System Control Unit (SCU), MPFM flow computer and the MPFM 1900VI Service Console Program (SCP). The SCU is used to control and distribute the flow of gas and multiphase flow to the Coriolis gas flow meter and the MPFM 1900VI® multiphase flow meter respectively; while the SCP is the operator’s access point to the Roxar MPFM 1900VI.

The photo below shows the final HG-MPFM produced for EGDP01.

Figure 3 EGDP01 HG MPFM

3.1.4. Capacity and Operating Envelope – The deliverables. The nominal operating envelope of HG-MPFM system is firstly determined by the operating envelope of Roxar MPFM 1900VI and then extended by parts of the capacity of a 3” Coriolis meter in BSP’s case. The operating envelope of 2” (ID 49mm) Roxar MPFM 1900VI with a beta ratio of 0.7 as used by EGDP01 is shown on the following table.

Table 2 Operating Envelope Roxar MPFM 1900VI for EGDP01

Q Liquid (am3/d) Q Gas (am3/d) GVF %

Minimum Maximum Minimum Maximum

10 252 2520 28 280

30 242 2424 96 960

50 206 2064 206 2060

60 178 1776 267 2670

70 144 1440 334 3340

80 103 1032 409 4090

90 55 552 480 4800

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A DN 80 coriolis meter with nominal capacity of 1,800,000 sm3/d is required to extend the operating envelope. The operating envelope of the HG-MPFM system then became suitable to cope with the project requirement of 2000 m3/d of liquid and 2,000,000 sm3/d gas at 6500 kPa. The overall HG-MPFM operating range for EGDP01 is shown below

0,0

500,0

1 000,0

1 500,0

2 000,0

2 500,0

3 000,0

3 500,0

0,0 5 000,0 10 000,0 15 000,0 20 000,0 25 000,0 30 000,0 35 000,0Qgas (Am3/d)

Qli

qu

id (

Am

3/d

)

Min / max, MPFM

Operating range, Hi-Gas

30 %

60 %

80 %

90 %

96 %

98 %

Figure 4 EGDP01 HG MPFM Operating Envelope

3.2 Project phase The CWDP01 and EGDP01 are operated by different asset units in BSP. Two different project teams were established to manage the projects. Similarly on the vendor side, two different project managers handled the execution of CWDP01 and EGDP01. The CWDP01 HG-MPFM project execution came earlier than the EGDP01. There was some difficulty during project execution of CWDP01 mainly due to unfamiliarity of the vendor and its subcontractors with BSP specifications and procedures. There were lots of improvements on the EGDP01 project when the vendor and subcontractors became more and more familiar with BSP requirement. However, it is not the intention of this paper to discuss details around the project execution aspects, but rather to look at main operational aspects of the HG-MPFM as they are believed to be of more value to the reader. This leads on to the next section. 3.2.1. Dynamic Flow calibration, CWDP01 HG-MPFM The purpose of the dynamic flow calibration is to verify that the HG-MPFM will operate according to its specification under actual and dynamic conditions. The flow test was performed at Christian Michelsen Research’s (CMR) flow loop in Bergen, Norway. The test consisted of 13 flow rig set points, each resulting in three single measurement points (liquid flow rate, gas flow rate and water-in-liquid ratio - WLR). In addition to this the control system algorithm was tested, comprising 6 flow rig set points.

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The CMR loop’s operating pressure was 1-2 bar(g) nominal with maximum liquid flow rate 90.5 m3/d and maximum gas flow range 7 – 100 am3/d. It is clear that the test scenario was quite different from the actual dynamic conditions expected in the Champion West field. Although the HG-MPFM met the acceptance criteria, the main purpose of the dynamic test could not fully be achieved since the testing was done far below than the typical CWDP01 operating conditions. 4 Commissioning CWDP01 MPFM Initially, the CWDP-1 HG-MPFM was commissioned at the end of December 2005. Unfortunately the commissioning was not very successful as the CW-29 well produced a very high flow rate; much higher than the operating envelope of the HG-MPFM. The HG-MPFM recorded flow rate was exceeding 3000 m3/d of liquid. Referring back to chapter 3.1.1, the design flow rate is 2000 m3/d of liquid. That condition caused:

• Decrease of cyclone separation efficiency.

• Difficulties to set-up and tune the control valves. The high flow rate resulted in an unexpected control system response as it operated outside the designed operational envelope.

• Liquid carry over to the gas leg leading to inaccurate coriolis measurements or even erratic readings.

• An excessive differential pressure across the MPFM and also across the skid, which triggered a wellhead shutdown! The graph below shows details of what happened.

Flow Rate - Pressure Drop

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

9:36 10:48 12:00 13:12 14:24 15:36 16:48 18:00

Time

Flo

w R

ate

m3

/d

-500

0

500

1,000

1,500

2,000

2,500

DP

Kp

a

Total gas Actual (m3/d) Total Liquid Actual (m3/d)

HG MPFM Pressure Loss MPFM DP

Figure 5 Actual Flow Rates and DP during the first commissioning

In addition to the above instances triggered during the first commissioning, it was discovered that the well test function software was not included in the HG MPFM SCP. To avoid further

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deferment, the project team consequently decided to stop the commissioning of CWDP01 HG-MPFM pending the vendor analysis report of the behavior and performance of HG-MPFM when beyond its operating envelope. Fortunately, the dynamic calibration test of the EGDP01 had not been conducted at this point in time. The vendor and EGDP01 project team therefore agreed to include the CWDP01 operating scenario during the scheduled dynamic flow calibration test at K-Lab. This will be further explored in section 3.2.3. Although the above may come across as blow to the project, it should be noted that the CWDP01 HG-MPFM was the first High Gas system designed and supplied by Roxar to Shell Operating Units globally. With more comprehensive preparation, improved vendor support and most importantly – the production rate depleting to within the MPFM operating envelope, the HG-MPFM for CWDP01 system was successfully re-commissioned on early of May 2006 for oil wells. An interesting note for the 2nd commissioning is that the accuracy of the HG MPFM was not verified by comparing with a reference meter. Neither test separator nor other multiphase measurement devices where available at site during the commissioning. Instead, a comparison of several well-test results on the same well in a manner leading to a repeatability check was undertaken. The result was excellent. During the commissioning, the HG-MPFM was also used to test the well at different choke opening as shown in the following figure.

Figure 6 Choke Setting Effect on CW-28

The above test confirmed the choke valve characteristic is in accordance with specified flow curve by the manufacturer. 4.1.1. Dynamic Flow Calibration, EGDP01 HG-MPFM

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Similar as the CWDP01, the EGDP01 MPFM was dynamically flow calibrated to verify that the meter would operate according to its specification under actual and dynamic conditions. What was different from the CWDP01 scenario was the testing facility, ie. K-Lab; and a special mission from the CWDP01 project team to investigate the behavior and accuracy of the HG-MPFM when operating beyond its operating envelope. K-Lab is a high pressure wet gas test facility in Norway allowing ‘real life’ testing of multiphase flow meters as both pressure and liquids are true process ‘parameters’. The dynamic flow test of EGDP01 covered a test matrix consisting of twenty flow rig set points reflecting the Egret operating conditions; each test point resulting in three single test points (liquid flow rate, gas flow rate and water cut). In total there was 66 test points in the test matrix including additional 6 repeated test points. No more than 10% of the test points could be outside the meter's performance criteria (when uncertainty of the loop is included in the uncertainty evaluation). The EGDP01 HG-MPFM was compared with the K-Lab reference measurements, with logging time 5 – 10 minutes. The final result showed that the HG MPFM passed the test and met the vendor’s uncertainty budget. In total no more than 8, 3 % of the points were outside the performance criteria. More interesting perhaps, was the special mission to test the HG-MPFM beyond its operating envelope. This was done to simulate the Champion West operating scenario during the first commissioning, i.e. a Red Line Test. The HG-MPFM was tested at a liquid flow rate as high as 3450 m3/d – almost 75% above the design flow boundaries; with gas flow rate approximately 400,000 sm3/d. The red triangles in the graph below show what flow rates were subjected to the meter. These also simulate flow scenarios experienced during the first commissioning of the CWDP01 HG-MPFM.

Figure 7 Test Flow Rates compared to operating envelope

Amazingly, the HG MPFM survived the extraordinary testing which brought the MPFM through the extreme mix velocity of more than 50 m/s. The system was capable of catering to the

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change in GVF and to measure the gas flow rate within the specified uncertainty. It did however overestimate the liquid flow with approx 10 – 15% as shown on the following graph. Still not too bad when boosted out by 75%!

4.1.2. Commissioning EGDP01 MPFM The EGDP01 HG MPFM was commissioned on June 2006. Lesson learns gained from CWDP01 projects and from the K-Lab flow test, combined with a more experienced commissioning team resulted in a smoother and faster commissioning. But, still not 100% trouble free. The difference of operating regime between HP oil wells and HHP gas well required the vendor to upgrade and modify the high gas cybernetic control software to minimize surges during the flow line switching. Practically, the total required time to bring the HG MPFM into full function operation was less than 18 hours. The commissioning was very productive; 16 well tests could be performed within three short days, still prolonged due to bad offshore weather. High confidences in meter results were achieved through repetitive well testing on stable wells proving excellent meter repeatability. The graph overleaf provides a snap shot of one of these well tests. Stable and smooth well test results indicate a good control system where the cybernetics are doing its job in terms of keeping the MPFM in its ‘sweet spot’ and the Coriolis free from liquid carry over.

Liquid Flow Rate K-Lab Vs HG MPFM

0

500

1000

1500

2000

2500

3000

3500

4000

15:57 16:01 16:06 16:10 16:14 16:19 16:23 16:27

Time

Flo

w r

ate

m3/d

HG MPFM Liquid rate K-Lab Liquid rate

Figure 8 HG-MPFM vs K-Lab Reference Meters

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28 June 2006 Well Testing

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

7:2

0

7:4

3

8:0

6

8:2

9

8:5

2

9:1

5

9:3

8

10

:01

10

:24

10

:47

11

:10

11

:33

11

:56

12

:19

12

:41

13

:04

13

:27

13

:58

14

:21

14

:44

15

:07

Time

Gas F

low

Rate

0

200

400

600

800

1000

1200

1400

1600

GasRate Sm3/d Oil Rate Sm3/d WaterRate Sm3/d

EG-12S

EG-11 EG-14

EG-13 + EG-14

Figure 9 HG MPFM Well Testing, 28 June 2006

5 OPERATION 5.1 CWDP01 The CWDP01 is equipped with a Foundation Fieldbus DCS (FFDCS) for process control and monitoring and a combined ‘Instrumented Protective System / Fire and Gas System’ (IPS/FGS) for platform safeguarding. Well testing on CWDP01 is carried out remotely with wells being lined up to the test header by FFDCS controlled switching valves. Well specific parameters are stored in the HG-MPFM’s Flow Computer and selected via the FFDCS. Simply, the operator will only have to select the well ID and click the start button, and then automatically the system will conduct the well testing operation. Data from the well tests will be monitored by the FFDCS and transferred to Operation Control Center (OCC) for production management purposes. 5.2 EGDP01 The well testing operation on EGDP01 is similar with the CWDP01 except some operations being carried out locally in that wells are being lined up to the test header by manual switching of valves. 5.3 Well behavior Vs MPFM performance Once the HG MPFM is completely commissioned, the system will be able to handle various well conditions, including fluctuating and slugging wells. The flow line switching between HP oil regime to/from HHP can be done smoothly without surge.

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As long as no technical alarms occurs which means the high gas cybernetic control is in proper operation; the HG MPFM can maintain the GVF of the MPFM at the set value, avoiding liquid carry over through the coriolis meter; hence high accuracy measurement can be expected. The following graphs are the screenshots from the HG MPFM operator interface showing two wells with very different behavior.

Figure 10 Well Testing Snapshot CW-30

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[WP1]Figure 11 Well testing Snapshot CW-29

As indicated by figure 10 and 11 the Champion West fields have a production profile that is very alternating. Although no stable flow conditions are achievable during production across the certain field, the HG-MPFM is able to cope with the different flow scenarios providing BSP with valuable well tests. 5.4 Various Issues – Challenges 5.4.1. Software Bug As mention above, the accurate multiphase measurement by the HG MPFM can only be achieved when the HiGas cybernetic control is working properly. There have been a few occasions where the HiGas control system froze the gas or liquid control valve at certain positions. This caused liquid carry over into the coriolis meter as indicated by the increasing of coriolis excitation voltages. When this happens, technical alarms will be raised as the multiphase measurement uncertainty (particularly the gas flow rate) deteriorates. The HG MPFM is equipped with a watchdog system to monitor any error, and then reset the high gas software ensuring proper control system operation. A simplified flow chart illuminating the liquid carry over watchdog is provided below.

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Figure 12 functional control charts for Liquid carry over into coriolis

Unfortunately, and for unknown reasons the watchdog system fails to react when the control valve freezes and a liquid carry over situation occurs. The operator must reset the HiGas software manually to bring the system back into normal operation. For remote and unmanned platforms such as EGDP01 and CWDP01 this software bug provides operational stressors to BSP. A temporary solution whereby the windows operating system is configured to regularly reset the HiGas system has so far been helpful although this is not the preferable way to fix the problem. Roxar is currently working the software opting to rectify the situation, as the current condition is intolerable to BSP. 5.4.2. System Architecture The HG MPFM control system is equipped with two (2) PC’s run by Windows 2000 operating system. One PC complete with LCD touch screen is dedicated for the HiGas control system and the second PC with normal LCD flat screen is used as the operator interface. From the operator’s point of view, regardless of the reliability of Windows operating systems; using two PC’s with two monitors and two keyboards in the same cabinet to control a system such as the HG-MPFM is not found to be the best system architecture, neither a practical design! The different type of monitors is creating an awkward local operator interface. Anyhow, in case of CWDP01 and EGDP01 it is not really an issue as the well testing operation is normally performed from the FFDCS. 6 CONCLUSION This paper has shown that a complex metering challenge can be solved in a way requiring a small footprint, and omitting traditional measurement challenges such as operational difficulties in maintaining the liquid level/indication for high GVF wells It has also shown that true online response to well production is available, as well as achieving a high number of well tests with no or little ‘lost oil’ scenarios.

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As for a fast set-up time and ‘install and forget’ characteristics, it is apparent that the HG- MPFM system is more complicated than a standard MPFM. The presence of additional equipment such as a cyclone separator, coriolis meter and control valves aiming to handle a very wide range of GVF and various well behaviors require specific expertise to tune the control system. This means that thorough operator training is required in order to ensure proper operation during field life. When such prerequisites are adhered to the system have the ability to perform at expected levels. Although not cheap; the dynamic flow calibration as close as possible with the actual operating condition is strongly recommended; not only to verify the accuracy of the system but will ensure proper control system operation; hence will minimize the problem during site commissioning. 7 REFERENCES [1] NORWEGIAN SOCIETY FOR OIL AND GAS MEASUREMENT (NFOGM), Handbook

Of Multiphase Flow Metering; Revision 2, March 2005; [2] RFM-PR-00780-191.128 MPFM 1900 VI High Gas Dynamic Flow Test Procedure; K-

LAB TEST LOOP [3] RFM-TD-00172-191 MPFM 1900VI Performance Specification 8 ACKNOWLEDGMENT

The authors wish to thanks Glenn Samuelsen – Technical Manager of Roxar Flow Measurement for his support providing necessary technical information; data and pictorial to help make this paper possible.