IPTC-11193-MS-P

IPTC 11193 Planning and Executing Long Distance Subsea Tie-Back Oil Well Testing: Lessons Learned Amrin F. Harun, SPE, BP America*

Copyright 2007, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Dubai, U.A.E., 4–6 December 2007. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference 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, IPTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Three subsea oil wells in a water depth ranging between 5200 and 5400 ft in the Gulf of Mexico are tied back to a Tension Leg Platform via a flowline network of a single 2.3 miles pipe-in-pipe connected to a 17 miles dual active-heating flowline. During normal operation these wells flow to a common separator at the topsides. Production allocation to each well is done by subtracting the topsides separator measurement by the subsea multiphase flow meter reading dedicated to one of the wells and manually splitted between the other two wells. When the topsides separator started showing some water production, more rigorous well testing is required to know where the water comes from. The information is crucial for the depletion plan of the field. Since well testing would cause some production deferment, its objectives were expanded to include subsea pigging valve integrity testing, subsea multiphase flow meter validation, and rigorous fluid sampling. The program was executed smoothly and met all its objectives. The formation water was identified from the unexpected well; thus suggested re-visiting the reservoir model. Although not predicted by the transient simulation works, slugging was experienced when the weakest well was producing by itself but it was managed through topsides choking. The key success for the smooth operation was a well-thought plan developed by a multi discipline team and the guidelines based on transient simulation works. Introduction King and King West oil fields are 100% BP operated and located in the Gulf of Mexico (GoM). The fields consist of three subsea wells, i.e. King D5 and D6 wells and King West D3 well located in a water depth ranging between 5200 and 5400 ft. They are tied back to the Marlin Tension Leg Platform (TLP) located in 3200 ft water depth. D3 well is connected to D5 well through a 2.3 miles, 6 by 10 inches pipe-

in-pipe flowline. D5 and D6 wells are then connected to the TLP via a 17 miles, 8 by 12 inches dual active heating flowlines (Figure 1). The flowlines connecting D5 and D6 wells to the TLP are designated as the West and East flowlines, respectively. A remotely operated subsea pigging valve located close to D6 well is normally open. D5 and D6 wells are producing from the same reservoir while D3 well is producing from another reservoir. For reservoir management purposes, D3 well is equipped with a subsea multiphase flow meter (SS MPFM) located in a jumper between the wellhead and the flowline.

8x12 Dual ActiveHeating Flowline MPFM

Pigging Valve

Fig. 1- King/King West Field Layout

Marlin TLP processes production stream coming from 3 dry tree wells (two oil wells and one gas well) and 5 subsea wells (three oil wells and two gas wells). The well fluids go to three three-phase separator (HP, Test, and IP) set at the same pressure (Figure 2). The oil flows through the LP separator and the gas goes to the compression system before they both going to the export system. The produced water is treated and dumped overboard. D3, D5, and D6 wells are normally flow to the IP separator. However, the topsides piping and manifold systems allow any well to flow to any separator providing it does not upset the plant, mainly the water treatment process. D5 and D6 wells oil and gas production is allocated by the IP separator measurement after subtracting D3 well production measured by the SS MPFM. A certain ratio for each phase, obtained from reservoir simulation works, is then applied to split D5 and D6 oil and gas production. Since they are producing from the same reservoir, there is not much concern about the exact split of these two King wells. When

* Now with BP Egypt

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production curtailment occurs, D3 well sometime flows by itself; thus giving the opportunity to verify the SS MPFM performance against the topsides measurement.

To maximize the value of well testing program, the objectives have been expanded as follows: 1. Identify the water producer well among King/King West wells. 2. Evaluate the SS MPFM performance. 3. Test the SS pigging valve integrity. 4. Conduct rigorous oil, gas, and water sampling program. 5. Confirm the wellbore and flowline network model. Planning Activities Due to amount of pressures to justify production deferment against the value of data obtained from the well testing program, a thorough planning must be developed to assess the feasibility of the program. Multi discipline team consisting of subsurface, production chemistry, and operations evaluated different aspects to ensure all the objectives can be achieved. To present the business case to the management, the following activities had been performed: transient simulation works, thorough fluid sampling planning, SS MPFM performance testing plan, and operability assessments.

Fig. 2- Marlin TLP Process Flow Diagram

The operators had reported that a small amount of water (about 50 B/D or less than 1% water cut) was dumped occasionally from the IP separator, which was believed to be the condensed water. However, since the beginning of 2005, the water has been dumped more often with an average rate of 100 B/D. Based on the current geological model, the subsurface team believes that the water should come from D5 well. Since the depletion plan, including a new drilled well, for King/King West fields require better understanding of the reservoir, more surveillance becomes necessary to confirm the water producer well. Well Testing Issues To identify the water producer well, the wells must be tested individually. This can only be accomplished by closing the pigging valve and having two separators to receive fluids from each flowline. However, this also means production deferment particularly these three wells produce more than 80 percent of the TLP total oil production. To justify the well testing program, the following questions must be answered to convince the management: 1. Will the main objective to identify the water producer well be met? 2. Due to a small amount of water, can it be detected within a short period of time? 3. How long the wells need to be tested? 4. Due to a small amount of water, how long will it take for the water holdup in the flowline to build up and stabilize? 5. How much production deferment does this well testing cost? 6. Will slugging occurr causing plant shutdown or unstable measurement? To answers all the above questions, transient simulations works must be performed to determine: stabilisation time in the flowline and slugging tendency due to rate reduction and time for water holdup in the flowline to reach equilibrium.

Transient Simulation Works. Because of long distance tie-back system, most of the operations during well testing involve transient flow. In addition, rate reduction due to flowing one well from each flowline could encounter instabilities and lead into slugging. Therefore, transient simulation works become necessary to predict hydraulic nature of the well testing program particularly to answer the following questions: 1. How long the flowline will stabilize after a well is shut-in or opened? This will impact the well testing duration which consequently the production deferment. 2. Will the flowline slug due to less flow rate? This is to predict if slugging can still be managed and will not upset the platform. 3. How long does it take for water holdup in the flowline to reach an equilibrium or steady state condition? This is to ensure that the small amount of water will reach the topsides within a reasonable time and measurement is representative. 4. What is the flow rate for each well? This will determine the amount of rate reduction during well testing. Transient simulation works had been performed using OLGA 2000 commercial software as a transient multiphase flow simulator. Three-phase simulations, where water is treated as a separate aqueous phase, were performed for all of the simulation cases in this study. There can be slip between hydrocarbon liquid and aqueous liquid, particularly at low rates, and three-phase modeling will indicate higher liquid holdup than would two-phase modeling. More detailed theoretical background of the software can be found in Bendiksen et al.1 and Nunnes et al.2. By having the wellbores and the flowlines in the model, the simulator will do the computations and provide the following: 1. How long it will take for pressures and fluid rates in the system and liquid holdups in the flowline to stabilize once a well is opened or shut-in. This will be

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used as criteria to determine the stabilization time in the flowline. 2. How long it will take for water holdup in the flowline to reach steady state condition. This will indicate no more water build-up in the flowline and the water measured at the topsides will be representative. 3. Slugging tendencies coming to the topsides once a well is opened or shut-in. The wellbore and flowline network model is shown in Figure 3. Due to limitations in the software version used for this project, the East flowline must be modeled in “reversed” fashion since the network model must converge into one node. The model requires reservoir and topsides pressures as the boundary conditions. The model also requires a PVT file for each branch in the network. The influx from the reservoir into the wellbore is governed by productivity index constants. The software will then calculate pressures, temperatures, fluid rates, and holdups throughout the network as a function of time. Fluctuation in pressures and flow rates coming to the topsides and flow patterns in each branch are the indication of slugging tendency, which need to be confirmed by using slugtracking module in the software. The steps to simulate the well testing program were taken as follows: 1. Flow all three wells normally. 2. Close the pigging valve to allow D3 and D5 wells flowing through the West flowline and D6 well through the East flowline. 3. Close D5 well to allow D3 well to flow by itself through the West flowline. 4. Open D5 well and close D3 well to allow D5 well to flow by itself through the West flowline. For each step, the following observation was made: 1. How long it will take for wellhead pressures in each well and the rates coming to the topsides to stabilize. 2. How long it will take for liquid (particularly water) holdup in each flowline to reach equilibrium. 3. If pressures or fluid rates continue to fluctuate and slug flow regime is identified, slugging tendencies were further investigated using slugtracking module. The prediction was then benchmarked with the actual data when slugging was actually observed at the topsides. D3 Reservoir

D3 Wellhead D3 Flowline

D5 Reservoir

D5 Wellhead

West Flowline Topsides

D6 Reservoir East-West Flowline East Flowline Topsides

D6 Wellhead

Fig. 3- Wellbore and Flowline Network Model

Fluid Sampling Planning. Since the opportunity to get fluid samples from each King/King West well is very rare, thorough sampling program was planned carefully by the production chemist engineer. For further geochemistry and flow assurance studies, the following sampling program was designed: 1. Record Basic Sediment and Water (BS&W) for every 4 hours by taking samples from the separator oil outlet. For consistencies, BS&W will also be taken from the sampling point located at the topsides manifolds. 2. Check and document injection rates for any chemical injected into the King/King West system for every 6 hours. These include methanol, demulsifiers, defoamers, and corrosion inhibitors. 3. Obtain three corrosion inhibitor residuals during test (beginning, middle, and end of test). 4. Obtain 15 1-gallon oil samples from the separator oil outlet at the end of the test. 5. Obtain 2 1-gallon gas samples using evacuated cylinders at the end of the test. 6. Obtain 2 500-cc oil samples using water filled cylinders at the end of the test. 7. Obtain 1 500-cc water sample using evacuated sample cylinder at the end of the test. 8. Retain 2 6-oz oil samples at the end of the test for potential oil fingerprinting. 9. Obtain water analysis of HP separator just prior to putting D6 well and document which well(s) were in HP separator. 10. Test for CO2 and H2S using Draeger tube. Due to such an intensive sampling program, an outside contractor, rather than the operators, would be hired to specifically manage all the sampling duties. This turned out to be the right decision. SS MPFM Performance Testing. The reliabilility of SS MPFM performance is very critical not only for D3 well production allocation but also to indicate water onset for hydrate management since D3 flowline is not part of the active heating King flowlines. Unfortunately, the meter has experienced two serious problems: 1. For the last two years, it has given false water reading that also impacts its oil and gas measurements. 2. The densitometer part of the meter has failed to give any measurement, resulting in erroneous phase fraction and rate calculations. The first problem has been resolved by injecting 1 gal/min methanol. This practice has become a part of standard weekly well testing for D3 well. It is believed that the problem is due to static charge build-up caused by high rates coming from the well and the dryness nature of the oil. As an aqueous phase, methanol seems able to discharge the static charge build up. The theory will be confirmed once D3 well starts producing some water. For the second problem, a fixed density value based on the last reading when the densitometer was still working has been manually inputted. However, since the operating conditions continue to change, this number should be adjusted accordingly which then subject to uncertainties. Therefore, the meter vendor has suggested a different

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algorithm, called a non-gamma mode, to by-pass the density calculation completely. Since during well testing D3 well will flow by itself to a dedicated separator, it becomes an opportunity to verify the meter performance in both fixed-density and non-gamma modes and compare them against the topsides measurement. Therefore, the following program was planned when D3 well flows by itself: 1. Set the meter in the fixed density mode. 2. Inject methanol at 1 gal/min until water reading becomes zero and oil and gas readings are stable. 3. Stop methanol injection. 4. Switched the meter to the non-gamma mode. 5. Inject methanol at 1 gal/min until water reading becomes zero and oil and gas readings are stable. 6. Stop methanol injection. 7. Compare the meter readings for each mode against the topsides separator measurements. Operability Assessment. Intensive discussions were conducted with the operation team to ensure the well testing program could be executed in safely manner and meet all its objectives. The following concerns were addressed: 1. The integrity of the subsea pigging valve. Will it completely isolate the West from East flowlines? 2. The accuracy of water measurement at the topsides. 3. Impacts on water treatment process due to keeping the rest of Marlin wells into one separator. 4. Slugging tendency due to rate reduction The subsea pigging valve is normally open and it is designed to be open if there is a mechanical failure. The depletion plan for King/King West fields involves closing the pigging valve to mitigate slugging issues during late life. The accuracy of measurements also critically depends on the complete isolation of the West from the East flowlines. Therefore, it is important to confirm that the pigging valve can be fully closed. For this reason, a remotely-operated vehicle (ROV) is required to witness the valve closing operation. To avoid an extra cost for an ROV mobilization, it was agreed that the well testing program should be executed while some other subsea works involving an ROV were being performed around the King field area. To minimize erosion across the valve, the standard operating procedure requires pressure balance across the valve during opening or closing the valve. Based on the above discussion, the pigging valve operation would be performed as follows: 1. Since pressure gauges are located at the wellhead, adjust the topsides choke to create wellhead pressure (WHP) differences between D5 and D6 wells that would create a pressure balance across the valve. The water depth difference creates approximately 50 psi hydrostatic pressure between D5 (to be shallower) and D6 wells. 2. Confirm pressure balance across the valve by reading the WHP gauges at D5 and D6 wells. 3. Spot an ROV at the valve location. 4. Close the valve remotely from the topsides. 5. Observe any change in WHP. 6. Fly the ROV to confirm that the valve is closed. 7. Cycle the valve several times under ROV watch to

confirm the valve stem movement to fully closed position. 8. Keep the valve in closed position throughout the duration of the well test. 9. Open the valve once the well test program is completed by applying pressure balance across it. Measuring water production accurately from a well with water cut less than 1% is already a challenging task. The turbine meter in the water outlet of the separator is not sized to measure such small amount of water. Therefore, water rate can only be measured by dumping the water manually during the well test period. To maintain accuracy, the initial water level indicator must be set at a certain level prior to well testing. At the end of the well test the water must be dumped until the water level indicator drops to the initial setting. Oil sample is also collected from the oil outlet of the separator to obtain BS&W to measure the amount of water mixed in the oil stream. The demulsifier injection rate must be adjusted so that the correct BS&W would be obtained while the stability of subsequent water treatment process was also maintained. Both amount of the dumped water and water mixed in the oil stream were then added to obtain a total water production rate. For consistencies, BS&W measurement would also be obtained by collecting oil from the sampling point located at the topsides manifolds. Due to 17 miles distance between the well and the separator, there were concerns whether a representative water measurement can be obtained when only one well produces into the flowline. Water could continue building up in the flowline; thus a true measurement at the topsides could never been obtained within the well testing duration. The only way to answer this question is by predicting the time required for water holdup to reach its steady state condition, which was one of the expected outcomes of the transient simulation works. Since the well testing program requires two dedicated topsides separators, the remaining wells have to go to one separator. There were concerns that mixing the produced water and condensate from different wells might cause phase separation and subsequent water treatment process. However, the problem could still be managed to a certain extent by adjusting the chemical dosages (demulsifiers, water clarifier, etc.). The main concern was the slugging tendency due to rate reduction during well testing. Although it would not necessarily shutdown the plant, slugging becomes a troublesome for the operators to continuously monitor the entire processing system, among others separators performance and export oil pumps, and adjust some process variables manually. The current slug management is by adjusting the topsides choke, which consequently cause some production deferment. Therefore, one of the main objectives of transient simulation works was to assess slugging tendencies during well testing. Transient Simulation Results Slugging Analysis. OLGA Slugtracking module has been used for slugging analysis. For each case being simulated, the simulator was first run without the slugtracking module until steady state condition was reached. The same case was then

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IPTC 11193

5

350

300

Slug Length (m)

250

200

150

100

50

0 0

0.5

1.0 Time (hr)

1.5

2.0

Fig. 6- Slug Length Coming Topsides from East Flowline 2000

1500

Slug Length (m)

re-run for a short period of time, typically for 2 hours simulation time, with the slugtracking module. The results were then benchmarked with the actual data observed at the platform. The actual data was also used as the base line to assess if a new operating condition will result in unmanageable slugging. In May 2006, all King/King West wells were producing at an average of 33000 BOPD, 54 MMscfd, and 100 BWPD. During normal operation all subsea and topsides production chokes are typically at fully open position and the normal arrival pressure at the topsides is about 400 psig. Using all the available rates, pressures, and temperatures data, Figures 4 and 5 show the total liquid rate coming to the topsides from the East and West flowlines, respectively. Unfortunately, these rates can not be compared to the actual data since all fluids normally go to one separator. Note that the rates are expressed at separator condition, not stock tank condition. Note also since the East flowline is modeled in “reversed” fashion, the rate is expressed in “negative” value. Figures 6 and 7 show slug length coming to the topsides from the East and West flowlines, respectively. Since no slugging was observed at the TLP at this condition, these figures were used as the base lines for assessing slugging tendency for other operating condition. The 24-hour simulation without slugtracking show flow rates split between the West and East flowlines to be 45/55 for oil and 65/35 for gas (Figures 8 and 9). 0

1000

500

-10,000

-20,000

0 0.5

1.5

2.0

-40,000

20,000 -50,000

15,000

-60,000

-70,000

-80,000

0

0.5

1.0 Time (hr)

1.5

2.0

Fig. 4- Total Liquid Rate Coming Topsides from East Flowline 50,000 45,000

10,000 West Flowline 5,000

0

-5,000

-10,000

East Flowline

-15,000

40,000

-20,000 0

35,000 Total Liquid Rate (B/D)

1.0 Time (hr)

Fig. 7- Slug Length Coming Topsides from West Flowline

Oil Rate at Standard Condition (B/D)

Total Liquid Rate (B/D)

0

-30,000

5

10

15

20

25

Time (hr)

Fig. 8- Oil Rate Split Between West and East Flowline

30,000 25,000 20,000 15,000 10,000 5,000 0 0

0.5

1.0 Time (hr)

1.5

2.0

Fig. 5- Total Liquid Rate Coming Topsides from West Flowline

In the same month, some operating problems had forced D6 well to be shut-in for a couple days and due to rate reduction the operator had to pinch back the topsides choke to manage slugging. The topsides chokes in the West and East flowlines were pinched back to 23% and 61%, respectively. These actions resulted in 900 and 400 psig arrival pressures in the West and East flowlines, respectively. Figures 10 through 13 show the comparison of the total liquid rates and slug length between these conditions with the base line. The comparisons show no significant difference between the two

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IPTC 11193

cases, which confirms that slugging were manageable for both cases as proven by the actual condition.

350

300 Base Line

150 Slug Length (m)

Gas Rate at Standard Condition (MMscfd)

250

100 West Flowline 50

Choking due to D6 Shut-in

200

150

100

0 50 0

-50

0

East Flowline

0.5

1.0 Time (hr)

1.5

2.0

Fig. 12- Slug Length Coming Topsides from East Flowline: Choking Due to D6 Shut-in vs. Base Line

-100

-200

2000

0

5

10

15

20

25

Time (hr)

Fig. 9- Gas Rate Split Between West and East Flowline Base Line 1500

0

Slug Length (m)

-10,000

Total Liquid Rate (B/D)

-20,000 -30,000

1000 Choking due to D6 Shut-in

-40,000

500

-50,000 Choking due to D6 Shut-in

Base Line

-60,000 -70,000

0 0

-80,000

0

0.5

1.0 Time (hr)

1.5

50,000 Base Line Choking due to D6 Shut-in 40,000 35,000 Total Liquid Rate (B/D)

1.5

2.0

2.0

Fig. 10- Total Liquid Rate Coming Topsides from East Flowline: Choking Due to D6 Shut-in vs. Base Line

30,000 25,000 20,000 15,000 10,000 5,000 0 0

1.0 Time (hr)

Fig. 13- Slug Length Coming Topsides from West Flowline: Choking Due to D6 Shut-in vs. Base Line

-90,000

45,000

0.5

0.5

1.0 Time (hr)

1.5

2.0

To further analyze slugging tendencies, simulations were performed if no choking were performed when D6 was shutin. Figures 14 through 17 show the comparison of the total liquid rates and slug length between the no-choking case with the base line. The comparisons in the East flowline (Figures 14 and 16) show more intermittent liquid rate and longer slug for no-choking case as compared to the base line, which could be the indicator for unmanageable slugging. Meanwhile, the comparison in the West flowline (Figures 15 and 17) show no significant difference, which indicates that slugs do not occur in the west flowline. Comparing to the choking case (Figures 10 and 12), a lesson can be drawn that slugging due to D6 well shut-in (located in the East flowline) can be managed by reallocating more fluids to the East flowline by pinching back the topsides choke in the West flowline. This action does cause some production loss. However, it is still better than having unstable operating condition at the platform and more labor intensive situation to manage the operation.

Fig. 11- Total Liquid Rate Coming Topsides from West Flowline: Choking Due to D6 Shut-in vs. Base Line

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2000

0 -10,000

Base Line 1500

-30,000

Slug Length (m)

Total Liquid Rate (B/D)

-20,000

-40,000

-50,000

D6 Shut-in but No Choking 1000

Base Line

-60,000

500

-70,000 D6 Shut-in but No Choking -80,000 0

0.5

1.0 Time (hr)

1.5

0

2.0

Fig. 14- Total Liquid Rate Coming Topsides from East Flowline: D6 Shut-in but No Choking vs. Base Line

0

0.5

1.0 Time (hr)

1.5

2.0

Fig. 17- Slug Length Coming Topsides from West Flowline: D6 Shut-in but No Choking vs. Base Line

60,000 D6 Shut-in but No Choking 50,000

Total Liquid Rate (B/D)

Base Line

40,000

30,000

20,000

10,000

0 0

0.5

1.0 Time (hr)

1.5

2.0

Fig. 15- Total Liquid Rate Coming Topsides from West Flowline: D6 Shut-in but No Choking vs. Base Line 450 D6 Shut-in but No Choking 400

Slug Length (m)

350 Base Line

300 250

Flowline Stabilisation Time. The time for the total liquid rate coming topsides to become stable can be used to predict stabilisation time in the flowline after operating condition changes. Starting with all three wells flowing, Figures 18 and 19 show it takes about 8 and 5 hours for the East and West flowline to stabilize, respectively, after the pigging valve is closed. Another parameter to estimate flowline stabilisation time is the time for liquid holdup in the flowline to reach steady state after operating condition changes. Figure 20 shows it takes about 7 hours for the West flowline to stabilize after the pigging valve is closed and D3 well is shut-in to allow D5 well flows by itself. The figure also shows about 7500 BOPD net loss due to D3 shut-in and rate increase from D5 when flowing by itself. Since the existing reservoir model suggested D5 well to produce some water, the simulation was run with D5 well producing 100 BPD of water. Figure 21 shows water holdup in the flowline reaches equilibrium after 6 hours. It means that after 6 hours the topsides separator should measure the true water production from D5 well even with D3 well shut-in since there will be no more water accumulation in the flowline. The figure also shows that water holdup in the West flowline has to reach new equilibrium from 6.3 to 10.4 bbls after D3 well is shut-in as the oil and gas rates in the flowline change.

200

-5,000

150 100

0 0

0.5

1.0 Time (hr)

1.5

2.0

Fig. 16- Slug Length Coming Topsides from East Flowline: D6 Shut-in but No Choking vs. Base Line

The same exercises were continued to investigate different scenarios to be encountered during well testing including when the pigging valve is closed, only one well is allowed to flow in the West flowline, and flow two wells through a single flowline by closing one of the topsides chokes. The results are summarized in Table 1, which also show the oil and gas rates reduction for each scenario.

Total Liquid Rate (B/D)

-10,000 50

-15,000

-20,000

-25,000 0

5

10

15

20

25

Time (hr)

Fig. 18- Total Liquid Rate Coming Topsides from East Flowline After Pigging Valve is Closed

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Table 1– Simulation Results Summary

30,000

Wells

Pigging Valve Status

Total Oil (BOPD)

Total Gas (MMscfd)

Slugging

Oil Reduction (BOPD)

Gas Reduction (MMscfd)

Stabilization Time (hrs)

D3, D5, D6

Open

33100

53.7

No

0

0

0

D3, D5, D6

Closed

33100

48.6

No

0

5.1

8

D5, D6

Closed

25600

45.8

No

7,500

7.9

7

D3, D6

Closed

28200

31.1

No

4,900

22.6

5

Total Liquid Rate (B/D)

25,000

20,000

15,000

10,000 0

5

10

15

20

25

Time (hr)

Fig. 19- Total Liquid Rate Coming Topsides from West Flowline After Pigging Valve is Closed 27,000

2,000 1,964

24,000

1,891

22,000

1,818

20,000

1,745 Total Liquid Volume

18,000

Total Liquid Volume (bbls)

Total Liquid Rate (B/D)

Total Liquid Rate 26,000

1,673

16,000 0

5

1,600 15

10 Time (hr)

Fig. 20- Total Liquid Holdup in West Flowline (black) and Total Liquid Rate Coming Topsides from West Flowline (red) After Pigging Valve is Closed and D3 Shut-in 11

Total Water Content (bbls)

10

9

8

7

6

0

2

4

6

8

10

12

Time (hr)

Fig. 21- Water Holdup Build-up in West Flowline After D3 Well Shut-in

The same exercises were continued to investigate different scenarios to be encountered during well testing. The results are summarized in Table 1, which also show the oil and gas rates reduction for each scenario. Using both flowline, stabilization time in the flowline due to changes in operating condition ranges between 5 and 8 hours. Thus, the well testing program can be executed within reasonable time.

Finalizing the Program. After completing the simulation works and many discussions with all the parties involved consisting of subsurface, production chemistry, and operation teams, the well testing program was finalized. Supported by mainly transient simulation works, the management was convinced that the program was operationally feasible and the objectives of the well testing could be met. Since the production data and fluid samples to be obtained during well testing are essential for depletion plan of the field, the production deferment.during well testing would be acceptable. The final key objectives of the well testing were: • Identify the water producing well among King/King West wells. • Verify SS MPFM performance and test non-gamma mode. • Conduct rigorous oil, water, and gas samples from each well. • Confirm the subsea pigging valve integrity. To accomplish the above objectives the high level well testing program was finalized as follows: 1. Move all wells from HP to Test separators (Day-1) 2. Align the East flowline to allow D6 well flowing to HP separator 3. Close the subsea pigging valve 4. Shut-in D5 well to allow D3 well flowing by itself to IP separator 5. Evaluate SS MPFM performance by injecting methanol to D3 well 6. Test SS MPFM performance in non-gamma mode 7. Open D5 well, shut-in D3 well, keep D6 well in HP separator (Day-2) 8. Open the SS pigging valve, open D3 well (Day-3) 9. Keep D6 well aligned to HP separator and D3 and D5 wells to IP separator. 10. Back to normal production mode by aligning the East flowline to IP separator (Day-4) 11. Conduct rigorous oil, gas, and water sampling throughout the test The whole well testing program would take four days with an estimated rate reduction as follows: • Day-1: 4900 BOPD and 22.6 MMscfd due to net impact of D5 well shut-in and pigging valve closed. • Day-2: 7500 BOPD and 7.9 MMscfd due to net impact of D3 well shut-in and pigging valve closed • Day-3: Nil • Day-4: Nil

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IPTC 11193

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Executing the Program Closing the Subsea Pigging Valve. The program was started with a Joint Safety and Environment Assessment meeting to ensure all personnels involved in the program aware of any safety and environment issues during execution of the program. The program was executed as planned started by moving the remaining wells to Test separator to allow the other two separators be dedicated for the program. The topsides valves were adjusted to align the East flowline, where D6 well would flow by itself, into HP separator. The West flowline was kept aligned to IP separator (Figure 22). The orifice plate at the gas outlet of each separator was fixed with the correct size to ensure measurements would be within the recommended range. Subsea operation team was contacted to ensure that an ROV was in the area prior to closing the subsea pigging valve. To anticipate slugging potential due to pigging valve closing, the topsides chokes in the East and West flowlines were pinched back to 20% and 50%, respectively. After pressures equalization was confirmed across the pigging valve, the valve was cycled for three times while witnessed by the ROV. The WHP in D5 and D6 wells responded accordingly supporting what had been witnessed by the ROV. The pigging valve was kept closed after the ROV left the location. These activities confirmed the integrity of the pigging valve to isolate the West from East flowline; thus, the program could proceed as planned. PI9620-3 TI9610-1

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WEST HP

PI9620-5/6

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P HV9620-KF

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East Flow line

IP HV9621-1 Test

production was ramped slowly by opening the topsides choke from 20 to 40% within 8 hours period. The choke was further increased to 55% within 2 hours period. This is much longer than 5 hours stabilization time predicted by the simulation. One of the reasons could be because the simulations were run with the topsides choke in fully open position prior to closing the pigging valve while in reality the topsides chokes were pinched back at 20%. However, as explained later, the topsides choke was pinched back again to 22% to reduce the rate fluctuation coming to the topsides. This indicates that the operating condition was worse than predicted by the simulation. One of the reasons could be due to lower reservoir pressure since the program was executed two months after simulation works. SS MPFM Performance Testing. The SS MPFM performance was set in fixed density mode. Once D3 well flowed by itself in the West flowline, methanol was injected at 1 gal/min but the water anomaly reading did not drop to zero as usual. Methanol injection rate was then increased up to 3 gal/min when the water reading dropped to zero. The injection rate was reduced back to 1 gal/min but the water anomaly reading started to appear. Thus, the injection rate was increased back to 3 gal/min. After 1 hour, the meter gave stable oil and gas measurements at 15622 BOPD and 17.3 MMscfd. Methanol injection was stopped and the meter was switched to non-gamma mode. After the meter was stabilized, methanol injection was again initiated at 3 gal/min. After 2 hours, the meter gave stable oil and gas measurements at 14219 BOPD and 21 MMscfd. Methanol injection was then stopped. The SS MPFM performance testing was finished and the meter was kept in non-gamma mode.

HV9620-1 HV9630-KF

HV9620-KG PI9630-3 P

West Flow line HV9630-KG T

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HP HV9632-1

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Fig. 22- Topsides Valves Arrangement to Align East Flowline to HP Separator and West Flowline to IP Separator

Testing D3 well in the West Flowline. The program continued by shutting-in D5 well to allow D3 well flow by itself in the West flowline. D3 well production was ramped-up slowly by opening the topsides choke from 50 to 100% within 1 hour period. The simulation was predicting 5 hours stabilization time for the West flowline. The difference could be because the simulations were run with the topsides choke in fully opened position prior to shutting-in D5 well while in reality it was pinched back at 50%. This shows that pinching back the topsides choke in anticipation of slugging shorten the flowline stabilization time. The water level in IP separator was set to begin 24 hours test. Testing D6 well in the East Flowline. D6 well had already been flowing by itself in the East flowline into HP separator since the pigging valve was closed. D6 well

Slugging in the East Flowline. The gas and oil rates measurements from HP separator, where D6 well was flowing into, kept fluctuating. Thus, the topsides choke was pinched back from 55% to 22% within 8 hours period. The gas and liquid rate measurements from HP separator were much smoother but 22% opening caused 725 psig back pressure to D6 well. This fact indicated that the East flowline was slugging but still manageable through toposides choking. Since this was not anticipated by simulation works, further investigation is needed. The water level in HP separator was set to begin 24 hours test for D6 well. D3 Well Testing Results. The 24 hours period for D3 well test was finished and the separator measurement gave 14900 BOPD, 22.8 MMscfd, and 0 BWPD. This confirms that D3 well does not produce water. Comparisons with the MPFM measurements indicate that the meter performs better in nongamma mode. Thus, it was kept in non-gamma mode. The fluid samples for D3 well were collected as planned. The estimated rate for D3 well based on simulation works was 16600 BOPD and 18.3 MMscfd. Since the simulation works were based on May 2006 data while the well testing was executed in July 2006, the rate differences could indicate that the reservoir pressure has already decreased and the gas oil ratio (GOR) has already increased. D5 well was opened and D3 was shut-in. The water level in IP separator was set to begin 24 hours test for D5 well.

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IPTC 11193

D6 Well Testing Results – First 24 Hours. The first 24 hours test period for D6 well was finished. The rate was measured at 7700 BOPD, 14.9 MMscfd, and 271 BWPD (3.6% water cut). The result was surprising since the reservoir model did not suggest water comes from D6 well. To further confirm the test results, D6 well was tested for another 24 hours. The fluid samples were collected as planned. The estimated rate for D6 well based on simulation works was 11500 BOPD and 12.8 MMscfd. For similar reasons as D3 well case, the rate differences could be attributed to lower reservoir pressure and higher GOR.

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5. D5 Well Testing Results. The 24 hours period for D5 well test was finished and the separator measurement gave 15800 BOPD, 24.3 MMscfd, and 0 BWPD. The result confirms that D5 well does not produce water, which contradicts the reservoir model. The fluid samples were collected as planned. The estimated rate for D5 well based on simulation works was 15200 BOPD and 27.1 MMscfd. Besides the reservoir pressure must be already much lower, the difference in gas rate could be due to some inaccuracies in assigning gas proportion between D5 and D6 in the beginning. D6 Well Testing Results – Second 24 Hours. The second 24 hours test period for D6 well was finished. The rate was measured at 7700 BOPD, 15.1 MMscfd, and 219 BWPD (2.8% water cut). The water rate was a bit lower than the first 24 hour test. One of the reasons could be due to a short disruption with demulsifier injection into the separator that might cause some water carried by the oil stream. However, it confirms that D6 well is the water producing well, not D5 well. End of Well Testing. The subsea pigging valve was open while the East and West flowlines were still aligned to HP and IP separators, respectively. Since more fluids were now produced through the East flowline, HP separator dumped another 83 bbls of water. This was expected since the East flowline had to reach new water holdup equilibrium as the oil and gas rates going through the flowline were increased. With the pigging valve open, HP separator measured 15500 BOPD, 24.7 MMscfd, and 123 BWPD. Meanwhile, IP separator measured 16900 BOPD, 25.1 MMscfd, and 0 BWPD. Note that the water rate measurement was much lower than the previous result. The reason is because after the pigging valve is opened D6 well, as the weakest well, suffers more back pressure from the other two wells. This further confirms that the water comes from D6 well. The flow rates split between the West and East flowlines was 52/48 for oil and 50/50 for gas, which were not the same as predicted by the simulation, which needs further investigation. When all the wells were aligned back to IP separator, the separator measured 31700 BOPD, 51.1 MMscfd, and 166 BWPD, which confirms that the simulation works were based on higher oil and gas rates. Conclusions The well testing program was executed smoothly and all the objectives were met. Some lessons learned that can be drawn from this project are as follows:

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Good and thorough planning by the multi-discipline team is the key success of the whole program. Transient simulation works played an important role in predicting the impact of transient operations; thus help assessing the feasibility of the program. Pre-cautions must still be exercised to anticipate slugging since the simulation works are not always based on the correct input data and assumptions. The well testing has provided invaluable information about the well performance and fluid sampling for reservoir surveillances and depletion plan of the field. The production deferment is higher than predicted by the simulation due to some extra pre-caution that the operators took to avoid process upsets during transient operations, which is a good practice. Besides better input data, the wellbore and flowline network model needs more refinement to better predict slugging tendency and fluid split between the flowlines. Pinching back the topsides chokes in anticipation of slugging shorten the flowline stabilization time and good practices for managing slug.

SI Metric Conversion Factors ft X 3.048* E-01 = m ft3 X 2.831 685 E-02 = m3 bbl X 1.589 873 E-01 = m3 psi X 6.894 757 E+00 = kPa in X 2.54 E+00 = cm gal X 3.785 412 E-03 = m3 Nomenclature BS&W = Basic Sediment and Water GOR = Gas Oil Ratio HP = High Pressure IP = Intermmediate Pressure MPFM = Multi Phase Flow Meter ROV = Remotely Operated Vehicle SS = Subsea PVT = Pressure-Volume-Temperature TLP = Tension Leg Platform WHP = Wellhead Pressure Ack The author wish to thank Ahmed Shoreibah, BP Marlin Production Engineer, Todd Blanchard, BP Production Chemist Engineer, Errol Dupre, BP Marlin Production Supervisor and the entire BP Marlin Operations Team for their assistances that resulted in successful King/King West well testing program. The permission granted by BP management to publish this paper is greatly appreciated. References 1. Bendiksen, K.H., Malnes, D., Moe, R., and Nuland, S.: “The Dynamic Two-Fluid Model OLGA: Theory and Application.” SPEPE, May 1991, 171-180. 2. Nossen, J., Shea, R.H., and Rasmussen, J.: “New Developments in Flow Modelling and Field Data Verification,” BHR Group 2000 Multiphase Technology, 209-222.

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