bhr multiphase conf - steady-state and interrupted production in deep water oil system

5/22/2018 BHR Multiphase Conf - Steady-state and Interrupted Production in Deep Water Oil System

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Steady-state, and interrupted, production through

a deep water black oil system

T Hill, T Johnson, V Hacala-Nicol

BP Exploration Operating Company,Sunbury International Centre for Business and Technology, UK

ABSTRACT

Operating information is presented on a deepwater black oil field that has two flowline-riser systems. The paper primarily concerns one of these systems in which a hydrate

blockage occurred during an abnormal operating condition resulting from sea-water

ingress. This system has three manifolds producing into the flowline-riser, with a

significant low point close to the middle of the >10 km flowline.

As background, steady state information on pressure drop and temperature drop is

presented for one flowrate case in each of the flowline-riser systems, with comparison to

OLGA predictions. Comments are also made on the prevailing flow regime.

The bulk of the paper covers assessment and modelling of liquid distribution in the

flowline-riser system after a process shutdown, and descriptions of the subsequentattempted re-start, the development of a blockage, and the resultant remediation

activities. Remediation involved use of riser base gas lift to remove liquid from the riser,

and this activity was also modelled using OLGA, with subsequent comparison to the

field data.

NOMENCLATURE

Symbol Description Units

dP Pressure drop between two locations bar

dT Temperature drop between two locations oC

d/s Downstream

FR Flowline-riser

FTA Flowline termination assembly

GOR Gas-oil ratio Sm3/Sm3

ID Pipe internal diameter m

ILT In-line tee

OLGA Transient multiphase flow simulator

J-T Joule-Thompson cooling

M1-1 First manifold (closest to host) in first production system

M1-2 Second manifold in first production systemM1-3 Third manifold in first production system

M1-4 Fourth manifold in first production system

M2-1 First manifold (closest to host) in second production system

BHR Group 2010 Multiphase 7 21


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M2-2 Second manifold in second production system

M2-3 Third manifold in second production system

P Pressure measurement bar

PT Pressure transmitter location

RB Riser base

RT Riser topRBGL Riser base gas lift

ROV Remotely operated vehicle

SIV Subsea isolation valve

TEG Tri-ethylene glycol

U Heat transfer coefficient W/m2/K

u/s Upstream

1 INTRODUCTION

BP currently produces ~200 MMtonnes/yr (4 MMbbl/d oil equivalent) oil and gas. Anincreasing proportion of this production is from deepwater fields, in a variety of

geographical locations. This paper concerns an oil field in more than 1300 m water

depth. Production is through several manifolds into two flowline-riser systems, then into

a host facility that can process 10 MMTonnes/yr (200 Mbbl/d) oil, and the associated

water and gas. Figure 1 shows the primary flowline-riser system discussed in this paper.

Operating data has been collected. Steady-state data is presented for the two systems,

showing flow rates, pressures, and temperatures. Flow regime is shown for one case.

For one of the systems data are also presented on a shutdown condition, showing the

amount and location of liquid in the system immediately after the shutdown. Adescription is then given of the re-start of production through the system, followed by

another shutdown because of high-pressure observed at the base of the riser.

M2-1Manifold

FTA

RBGLSupply

WellM2-2Manifold

WellM2-3Manifold

Well

P

ValveValveValve

P

P

P P PP

PP

M2-3ILTM2-2ILTM2-1ILT

upper

lower

M2-2

ILT d/ s

M2-2

ILT u/ s

M2-3

ILT d/ sM2-1

ILT u/ s

P PP

Riser top

pressure

Riser base

pressures

SIV

P P

M2-1Manifold

FTA

RBGLSupply

WellM2-2Manifold

WellM2-3Manifold

Well

PP

ValveValveValve

PP

PP

PP PP PPP

PPPP

M2-3ILT

M2-2ILTM2-1ILT

upper

lower

M2-2

ILT d/ s

M2-2

ILT u/ s

M2-3

ILT d/ sM2-1

ILT u/ s

PP PPPP

Riser top

pressure

Riser base

pressures

SIV

PP PP

Location Line length and elevation change

M2-3 M2-2 2.25 km and -15 mM2-2 M2-1 3.87 km and -24 m

M2-1 RB 6.07 km and +106 mRiser 1.56 km and +1342 m

Water depthRiser base upper PT @ -1285m

Riser base lower PT @ -1305mRiser top PT @ +32m

Figure 1 - Typical flowline - riser configuration

22 BHR Group 2010 Multiphase 7


3/17

The subsequent investigation of the cause of this high-pressure revealed that there had

been some seawater ingress through an incorrectly installed clamp covering a vent port

on a future tie-in slot, during a time period in which the umbilical core pressure was not

maintained above ambient seawater pressure. The mixing of production fluids with cold

seawater resulted in the formation of hydrates, which on subsequent shutdown resulted in

a pressure retaining blockage in the production flowline believed to be due to a highviscosity mixture of hydrates, oil, seawater and emulsion.

2 INFORMATION ON FLUIDS

2.1 Crude oil and associated gasThe crude oil is 0.865 specific gravity (32 API), with 125-170 Sm3/Sm3GOR and an oil

viscosity of 30 cP at 15C. Reservoir temperatures are in the range 75-95C.

Typical flowline inlet pressure during normal operation is 60-100 bar, with inlet

temperatures of 65-85C, giving a solution GOR in the range 50-90 Sm3/Sm3.

2.2 Produced waterThe produced water has a chloride content of 80-115,000 mg/l. The highest well water

cut during the operations described in this paper was 11 %.

2.3 Hydrate formationThe oil and associated gas have a tendency to form hydrates with the produced water.

The hydrate dissociation pressure at the seabed temperature of 4C is approximately 13.5

bar, compared to a design separator pressure of 30 bar. This dissociation pressure was

predicted using sea water, and is therefore conservative for normal operation.

An assessment of industry hydrate experience led to an assertion that for water cut less

than 5% there is a very low likelihood of flowline blockage even if hydrates do form.

3 INFORMATION ON THE FLOWLINE-RISER SYSTEMS

The flowline internal diameter is 283

mm. At the FTA linking the end of

each flowline and its respective riser

there is an ROV operated SIV (seeFigure 1).

3.1 Riser configurationWater depth at the deepest pressure

sensor in the riser is at 1305 m. The

risers comprise a rigid, near vertical

section from the swan neck at the

base up to 80m water depth. After

two rigid bends there is a flexible

riser, to accommodate host motion,

leading to a rigid spool piece whichruns up to 32 m above sea level to the

riser top boarding valve on the host

facility. A diagram of the riser

-1400

-1200

-1000

-800

-600

-400

-200

0

0 50 100 150 200

Horizontal length (m)

Elevation(m)

Figure 2 - Details of riser configuration



4/17

configuration is shown in Figure 2. For an oil-filled riser the static dP between riser top

and bottom pressure gauges is 105-110 bar.

3.2 Flowline - riser 1The FR 1 system has a 23 km flowline. Production into the system is from four

manifolds located at 0 km (M1-4), 3.5 km (M1-3), 8.5 km (M1-2) and 17.2 km (M1-1)from the upstream end. In terms of inclination, the flowline has three major sections, a

virtually flat section between M1-4 and M1-3, an uphill section (0.15 degrees) from M1-

3 to a high point downstream of M1-2 and a downhill section (0.75 degrees) from that

high point to the riser base. An OLGA model of this system was developed using

detailed topography from a seabed survey, and the riser description summarised above.

3.3 Flowline - riser 2The FR 2 system has a flowline of ~12 km total length, in two sections, with a change of

inclination half way along. The first section, ~6 km, slopes 0.36o downhill. The second

section also ~6 km long, slopes 1ouphill to the riser base. At the low point, the flowline

is ~100 m below the riser base (8.0-8.5 bar dP if oil filled). Flow into the system is fromthree manifolds located at 0 km (M2-3), 2.2 km (M2-2) and 6 km (M2-1) from the

upstream end. An OLGA model was similarly developed for this flowline - riser.

3.4 InstrumentationThe instrumentation available on each flowline - riser system is as follows:

pressures and temperatures at wellheads and on manifolds multiphase flowmeter in test header on each manifold pressures and temperatures along flowline at each manifold ILT pressures and temperatures at riser base below and above gas injection wye pressures and temperatures on host facility at riser top and in slug-catcher

Production flow rates are also available from the reconciled production allocation

system, given the choke settings of the various wells lined up to production.

3.5 Hydrate preventionThe main method for prevention of hydrate formation is wet insulation. Flowlines have

a design U= 2.5 W/m2/K (based on pipe ID), and risers U= 3.4 W/m2/K. This insulation

easily keeps flowing fluids above hydrate formation temperature over the design ranges

of production rates, flowing pressures and temperatures. Flowline design cool down

time is 12 hours minimum from 45C to 20C. If a shutdown is likely to exceed the cool

down time, then each system is displaced with dead crude from host storage tanks at aflowing velocity sufficient to remove any accumulated water.

Methanol injection is available to protect wellhead jumpers, manifold pipe work, and

connection from manifold into flowline, which have a design cool down time of 6 hours

from 65C to 20C. Neither methanol injection nor flowline displacement is undertaken

whilst the water cut in the respective flowline - riser system is less than 5%.



5/17

4 STEADY-STATE OPERATIONS4.1 Operating data for flowline - riser 1This section describes a steady state operating condition in the flowline - riser 1 system.

The combined production from all the flowing wells was about 12,000 Sm

3

/d oil. Table1 shows the flow through each of the manifolds. Measured pressure drop through the

system was 65.2 bar from manifold M1-1 to riser top, and a further 17.1 bar from

manifold M1-1 to manifold M1-4. Temperatures were 70C downstream of manifold

M1-1 ILT, and 58.8C at riser top. Under the above conditions, the riser base pressure

transmitter indicated fluctuations of 2.5 bar.

4.2 Flow regime for flowline - riser 1Figure 3 shows riser base pressure, and dP between riser base gauges. The dP variations

(0.3 bar over 20m) are somewhat less than the gas only / liquid only extremes of slug

flow (dP would move between ~0-1.5 bar), so the flow is more homogeneous. However,

as the gas expands up the riser there seems to be sufficient coalescence to generate largergas pockets leading to the greater variations in absolute pressure at the riser base.

Superficial gas and liquid velocities at riser base are ~2 and 3 m/s respectively, which is

consistent with dispersed bubble flow, but close to the transition to slug flow.

83

84

85

86

87

88

89

90

91

92

93

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5

Time (hours)

Pressure(bara)

0.75

1

1.25

1.5

1.75

2

2.25

2.5

2.75

3

3.25

dPLower-Upperriserba

sePI(bar)

Operating data riser base P

DP Lower - Upper Riser Base PI

Figure 3 - Riser base pressure, and riser base dP between gauges, vs time

4.3 OLGA predictions for flowline - riser 1For the section from M1-1 to riser top, OLGA predicted 66.7 bar dP and 11.6C dT, and

a further 17.7 bar dP and 16.7C dT between M1-4 and M1-1. OLGA steady state dP

and dT predictions are an excellent match (within 4%) to the operating data. Figure 4

shows the steady state pressure and temperature profiles predicted by OLGA. The

output from the PT gauges along the flowline at the manifold ILTs, production riser base

and riser top are super-imposed onto the predictions for comparison purposes.



6/17

30

40

50

60

70

80

90

100

110

120

130

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000 24000 26000

Pipeline length from M1-4 (m)

Pressure(bara)/Temp

erature(degC)

OLGA Pressure

Operating pressure data points

OLGA Temperature

Operating temperature data points

M1-4M1-3

M1-2

M1-1

Figure 4 - Flowline riser 1 measured pressure and temperature profiles vs OLGA

4.4 Operating data for flowline - riser 2Combined production from the flowing wells was about 10,000 Sm3/d oil, 2,000 SMm3/d

gas, and 300 Sm3/d water. Table 1 shows the flow from each manifold. Measured dP

through the system (Figure 5) was 65.4 bar from M2-1 to riser top, and a further 2.3 bar

between M2-3 and M2-1. The wellhead flowing temperatures were 69-79C.

Temperatures were 70.4C at manifold M2-1 downstream ILT, and 56.6C at riser top.

0

10

20

30

40

50

60

70

80

90

100

110

0 2000 4000 6000 8000 10000 12000 14000

Flowline - Riser 2 - Pipeline length from M2-3 (m)

Pressure(bara)/Temperature(degC)

OLGA Pressure

Operating Pressure data points

OLGA Temperature

Operating Temperature data points

M2-3 M2-2 M2-1

Figure 5 - Flowline riser 2 measured pressure and temperature profiles vs OLGA

4.5 OLGA predictions for flowline - riser 2For the flowline section from M2-1 to riser top, OLGA predicted 59.2 bar dP, and 14C

dT and a further 2.4 bar dP and 3.9C dT between M2-3 and M2-1, as shown in Figure 5.

OLGA steady state dP and dT predictions are in reasonable agreement (within 13%) with

the reported operating data. The output from the pressure and temperature gauges along

the flowline at the manifold ILTs, production riser base and riser top are super-imposed

onto the predictions for comparison purposes.



7/17

5 SHUT-DOWN OF FLOWLINE - RISER 2After a steady-state period similar to that described above (oil rate ~8,700 Sm3/d), this

system was shut down. During the initial period of shutdown, the riser top flow path into

the slug-catcher remained open, and the system de-pressurised normally through the

process to a riser top pressure of 28 bar. This depressurisation happened relativelyquickly, compared to the subsequent longer timescale cooling, and some liquid would

have been carried out of the system. A day later, pressures at M2-1 and riser base were

tending to equilibrium. Figure 6 shows the pressures at riser top, riser base, and at M2-1.

Pressure plots for riser top, riser base, S4

20

30

40

50

60

70

80

90

100

31-Dec

15:00

31-Dec

21:00

01-Jan

03:00

01-Jan

09:00

01-Jan

15:00

Pressure(bara)

M2-1

RB

RT

Shutdown

Cooldown

Steady state

Normal depressuring

Day 1 Day 2 Day 2Day 1 Day 2

M2-1Pressure plots for riser top, riser base, S4

20

30

40

50

60

70

80

90

100

31-Dec

15:00

31-Dec

21:00

01-Jan

03:00

01-Jan

09:00

01-Jan

15:00

Pressure(bara)

M2-1

RB

RT

Shutdown

Cooldown

Steady state

Normal depressuring


M2-1Riser and flowline dPs

4

5

6

7

8

9

10

11

12

13

14

31-Dec

15:00

31-Dec

21:00

01-Jan

03:00

01-Jan

09:00

01-Jan

15:00

Pressure

difference,

bar

RT-RB

RB-M2-1


Riser and flowline dPs

4

5

6

7

8

9

10

11

12

13

14

31-Dec

15:00

31-Dec

21:00

01-Jan

03:00

01-Jan

09:00

01-Jan

15:00

Pressure

difference,

bar

RT-RB

RB-M2-1

Riser and flowline dPs

4

5

6

7

8

9

10

11

12

13

14

31-Dec

15:00

31-Dec

21:00

01-Jan

03:00

01-Jan

09:00

01-Jan

15:00

Pressure

difference,

bar

RT-RB

RB-M2-1


Pressure drop over flowline -

RB-S4, S4-S3, and S3-S2

-1

1

3

5

7

9

11

13

31-Dec

15:00

31-Dec

21:00

01-Jan

03:00

01-Jan

09:00

01-Jan

15:00

Pressure

differ

ence,

bar

RB-M2-1

M2-3M2-2

M2-2M2-1


RB M2-1 M2-2 M2-3



-1

1

3

5

7

9

11

13

31-Dec

15:00

31-Dec

21:00

01-Jan

03:00

01-Jan

09:00

01-Jan

15:00

Pressure

differ

ence,

bar

RB-M2-1

M2-3M2-2

M2-2M2-1



-1

1

3

5

7

9

11

13

31-Dec

15:00

31-Dec

21:00

01-Jan

03:00

01-Jan

09:00

01-Jan

15:00

Pressure

differ

ence,

bar

RB-M2-1

M2-3M2-2

M2-2M2-1


RB M2-1 M2-2 M2-3

Figure 6 - Pressures, and dPs across riser and flowline sections

5.1 Measured static pressure drop and inferred liquid volumeGiven measured dP after cooldown for M2-1 to riser base (4.3 bar), the dP for M2 -3 to

M2-1 (0 bar), oil density, and flowline elevation profile, the volume of oil in the line was

estimated (N.B. M2-1 PT is 5 m above the low point, giving a small manometer effect).

Riser base to low point near M2-1 3.4 km, 210 m3

Low point to M2-1 PT up to 0.5 km, 30 m3

M2-1- M2-3 0 km, 0 m3

Total oil volume 3.9 km, 240 m3

5.2 Calculated liquid hold-upOLGA was used to simulate the shutdown and subsequent depressurisation, includingremoval/drainage of liquid and cooling of gas. The simulated resultant liquid

distribution is shown in Figure 7, corresponding to total liquid volume of 4.3 km, 275

m3. The OLGA-predicted liquid accumulation in the flowline upon shutdown is in

reasonable agreement with the reported operating data.



8/17

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000

Flowline-riser 2 length from S2 to RB (m)

Liquidhold

up(-)

-1420

-1400

-1380

-1360

-1340

-1320

-1300

Elevation

(m)

shutdown liquid holdup Topography

S3

S2

S4

R

221 m3

oil in low

point - RB54 m3 oil

in low

point - S3

Depth of M2-1 PT

Potential

manometer

effect between

these points

M2-2

M2-3

M2-1

RB

M2-3 to RB (m)

M2-2

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000


Liquidhold

up(-)

-1420

-1400

-1380

-1360

-1340

-1320

-1300

Elevation

(m)


S3

S2

S4

R

221 m3

oil in low

point - RB54 m3 oil

in low

point - S3

Depth of M2-1 PT

Potential

manometer

effect between

these points

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000


Liquidhold

up(-)

-1420

-1400

-1380

-1360

-1340

-1320

-1300

Elevation

(m)


S3

S2

S4

R

221 m3

oil in low

point - RB54 m3 oil

in low

point - S3

Depth of M2-1 PT

Potential

manometer

effect between

these points

M2-2

M2-3

M2-1

RB

M2-3 to RB (m)

M2-2

Figure 7 - OLGA flowline-riser 2 shutdown holdup plot

6 RE-START OF FLOWLINE - RISER 26.1 Lining up for production re-startAfter a week of being shut in, this flowline-riser system was prepared for re-start. As

previously mentioned, during the early stages of the period of shutdown, the riser top

boarding valve was open. Midway through the shutdown period there was a topsides

process trip which caused closure of the boarding valve, which then remained closed for

the remainder of the shutdown period until opened again immediately prior to re-start.

The SIV and all flowline valves upstream remained open throughout.

6.2 Commencement of productionProduction was re-started with flow from wells at M2-3, M2-1, and then M2-2 (which

had the only water producer) manifolds. Detailed pressure measurements are shown in

Figure 8. The riser base pressure began to rise as production was re-started, increasing

from 55 bar to a plateau of 140 bar. The plateau corresponds to an oil-filled riser (as per

section 3). This plateau value of pressure had been previously observed in the flowline-

riser 1 system, which slopes down to the base of the riser, but not in this system.

Pressure plots for riser top, riser base, and S4

20

40

60

80

100

120

140

160

180

07-Jan 00:00 07-Jan 01:00 07-Jan 02:00 07-Jan 03:00 07-Jan 04:00

Timeline

Pressure(bara)

M2-1

RB

RT

Shutdown

Production restart

Riser top valve opened

Gas-oil interfacethrough flexible riser

Gas-oil interface

reaches top of riser

Oil-water interfaceenters bottom of riser

Gas-oil interface

moving up riser

Oil produced from riser top

Day 8 Day 8 Day 8 Day 8Day 8

M2-1Pressure plots for riser top, riser base, and S4

20

40

60

80

100

120

140

160

180

07-Jan 00:00 07-Jan 01:00 07-Jan 02:00 07-Jan 03:00 07-Jan 04:00

Timeline

Pressure(bara)

M2-1

RB

RT

Shutdown

Production restart

Riser top valve opened

Gas-oil interfacethrough flexible riser

Gas-oil interface

reaches top of riser

Oil-water interfaceenters bottom of riser

Gas-oil interface

moving up riser

Oil produced from riser top

Day 8 Day 8 Day 8 Day 8Day 8

M2-1

Figure 8 - Riser base, M2-1 and slugcatcher pressures through production re-start



9/17

After about 30 minutes at this pressure, the riser base pressure began to increase further.

This was noticed by the operators, who were rightly concerned, and they shut this

flowline-riser 2 system back down, as they interpreted the increase in riser base pressure

as evidence of a developing blockage in the riser.

6.3

Actions taken on subsequent decision to shut-downOnce shut down, the SIV was closed in order to isolate the riser from the flowline. This

was also the correct course of action - given the view that the cause of the pressure

increase was a developing blockage in the riser - thus isolating the riser from any

upstream pressure source - thereby greatly reducing the potential for accelerating any

dislodged blockage material towards the host facility.

An investigation team was then set up to determine the cause of the final pressure

increase and to recommend the remediation steps required.

7 ANALYSIS OF CAUSE OF HIGH RISER BASE PRESSUREPressure measurements were then collated for the riser top, riser base, and each manifold

from before the original shutdown right through until after the aborted re-start (Figure 9).

The analysis was helped by the ability to separate the dP across the riser and the dP

across the flowline, which was possible because of the riser base pressure measurements.


0

20

40

60

80

100

120

140

160

180

31-Dec 01-Jan 02-Jan 03-Jan 04-Jan 05-Jan 06-Jan 07-Jan 08-JaTimeline

S4

RB

RT

Steadystate

Shutdown

Riser top valve

closed

Shutdown

Start of liquid

ingress

Flowline full, riserfilling

Production restart

Riser top valve

opened

Cool down

M2-1

M2-1

1 2 3 4 5 6 7 8 9

(days)


0

20

40

60

80

100

120

140

160

180


S4

RB

RT

Steadystate

Shutdown

Riser top valve

closed

Shutdown

Start of liquid

ingress


Production restart

Riser top valve

opened

Cool down


0

20

40

60

80

100

120

140

160

180


S4

RB

RT

Steadystate

Shutdown

Riser top valve

closed

Shutdown

Start of liquid

ingress


Production restart

Riser top valve

opened

Cool down

M2-1

M2-1

1 2 3 4 5 6 7 8 9

(days)

1 2 3 4 5 6 7 8 9

(days)

Figure 9 - M2-1, riser base and riser top pressures through whole period

7.1 Absolute pressure in the systemIn previous shutdowns, the pressure after cool down was constant until the next re-start.

However, in this case it can be seen on Figure 9 that the pressure at M2-1 began to rise

shortly after the cool down condition was reached. It continued to rise slowly for three

days, and then at an increased rate. This change of pressure gradient was found to be

coincident with the shutting of the riser top boarding valve previously mentioned. This

new rate of pressure rise continued until the sudden drop in pressure coinciding with theopening of the riser top boarding valve in preparation for re-start. Given that this system

was shut down, the unexpected increase in pressure was not noticed by the operators.

Pressure

(bara)



10/17

Pressure drop over flowline - RB-S4, S4-S3, and S3-S2

-1

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

31-Dec 01-Jan 02-Jan 03-Jan 04-Jan 05-Jan 06-Jan 07-Jan 08-Ja

Pressuredifferenc

e,bar

dP required to driveproduction through

M2-1M2-2 on restart

M2-1M2-2 starts filling


M2-1M2-2 full

Rapid drop of dP on shutdown

RB-S4

M2-2M2-3M2-2M2-3

M2-1M2-2

RB-M2-1 starts filling

RB-M2-1 full

Production start-up

1 2 3 4 5 6 7 8 9

Timeline (days)

RB M2-1 M2-2 M2-3

M2-1M2-2

Pressure drop over flowline - RB-S4, S4-S3, and S3-S2

-1

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

31

-Dec 01-Jan 02-Jan 03-Jan 04-Jan 05-Jan 06-Jan 07-Jan 08-Ja

Pressuredifferenc

e,bar

dP required to driveproduction through

M2-1M2-2 on restart



M2-1M2-2 full


RB-S4

M2-2M2-3M2-2M2-3

M2-1M2-2

RB-M2-1 starts filling

RB-M2-1 full

Production start-up

1 2 3 4 5 6 7 8 9

Timeline (days)

RB M2-1 M2-2 M2-3

M2-1M2-2

Figure 10 - dP across flowline sections RB-M2-1, M2-2-M2-1 and M2-3-M2-2

7.2 Pressure drop over flowlineThe plot of dP from M2-1 to the riser base is shown in Figure 10. Given that there is no

flow, this dP equates to a head of liquid, indicating the liquid left in the low point of the

system after the shutdown, as previously mentioned. It then shows the steady increase in

liquid head for the time when the riser top boarding valve was open, and then a reduced

rate of increase once that valve was closed late on day 6. This is followed by a period of

almost constant dP (9.5-10 bar) over the flowline, consistent with the flowline being full

of liquid, much of which was denser than oil. Production then re-started, with an

increase in flowline dP up to 14 bar as the rates increased, then returning to 10 bar on

shut down.

The dP plots for M2-1-M2-2 and M2-2-M2-3 show that after the shutdown there is no

liquid in these sections. As liquid filling occurs the upstream gas is compressed and

liquid moves towards M2-3, eventually passing M2-2 and filling ~4 km upstream of M2-

1 before re-start.

Riser and flowline dPs using RB lower gauge

4

6

8

10

12

14

16

18

20

22

24


Pressuredifference,bar

Previously observed cooldown effect


Riser top valve is closed

Gas bubbling through liquid in riser

Flowline full, and

liquid starts up riser

Production start-up riser dP is ~20 bar

Flowline filling

Riser liquid displacement

around flexible

Production start-up

Shutdown

RISER

FLOWLINE RB-S4

Timeline (days)

1 2 3 4 5 6 7 8 9

M2-1 Flowline dP aftershutdown no

blockage

Riser and flowline dPs using RB lower gauge

4

6

8

10

12

14

16

18

20

22

24


Pressuredifference,bar

Previously observed cooldown effect


Riser top valve is closed

Gas bubbling through liquid in riser

Flowline full, and

liquid starts up riser

Production start-up riser dP is ~20 bar

Flowline filling

Riser liquid displacement

around flexible

Production start-up

Shutdown

RISER

FLOWLINE RB-S4

Timeline (days)

1 2 3 4 5 6 7 8 9

M2-1 Flowline dP aftershutdown no

blockage

Figure 11 - dP across riser (also showing dP across flowline section RB-M2-1)



11/17

7.3 Pressure drop over riserFigure 11 shows the dP over the riser. On initial shutdown the pressure dropped rapidly

at first, and then slowly for an additional 12 hours. Once flow had stopped, this dP gives

an indication of the liquid column remaining in the riser. After cool down a pressure

increase is observed to 8.5 bar, followed by a slower rate of increase. There was a slight

increase in the rate of pressure increase after the closure of the riser top boarding valve.This was followed by a period of rapid pressure increase over the riser starting late day 6

(the two drops in dP are due to brief valve openings on the M2-3 manifold). The riser

top boarding valve was opened and production re-started (early day 8), with a fairly

rapid increase in riser dP up to a steady level of 140 bar (Figure 8). This was maintained

for 30 minutes until the further dP increase up to 159 bar, and the second shutdown.

Riser base pressure stayed at 159-160 bar after this shutdown, and through SIV closure.

7.4 Interpretation of pressure drop informationOn the first shut down there was a rapid reduction in pressure as expected, with the

flowline depressurising down to 40 bar at M2-1 (riser top open to 28 bar) and some oil

leaving from the riser top. Most of the remaining oil drained out of the riser into theflowline. Some oil was trapped in the low point of the flexible riser, and some above a

low point in the swan neck at the riser base. As the gas upstream in the flowline cooled

to equilibrium with theexternal sea water (4C) it contracted, and some of this oil moved

back into the flowline. This gave a further reduction in M2-1 pressure down to 35 bar,

and reduced the riser dP to the lowest value. The gas-oil interface was some 3.4 km

downstream from the low point near M2-1, as previously described.

Soon after this equilibration, significant amounts of additional liquid began to enter the

system. As this additional liquid entered the flowline, it displaced gas downstream and

into the riser. This gas bubbled through the oil at the riser base and added to the gas

volume in the riser. This displaced the oil trapped in the low point of the flexible riserforward such that there was a manometer effect, with the downstream leg of the flexible

riser holding more oil than the upstream, registering as an increase in riser dP to 8.5 bar.

Some gas was thereby also displaced out of the riser top. Eventually the oil here was

displaced sufficiently for gas to bubble up continuously through the downstream leg and

on out of the top of the riser at roughly constant pressure.

Then after the closure of the riser top boarding valve, liquid continued to enter the

system, thereby compressing the remaining gas. The gas compression resulted in an

increased rate of system pressurisation, but a slower rate of liquid entry. This process

continued until the M2-1 to RB flowline section was filled with liquid (with M2-1 to

M2-3 part filled), at which point the riser began to fill, thereby generating an increase in

pressure drop across the riser up to ~20 bar (corresponding to the gas-oil interface

reaching ~250 m up the riser). When production re-started this interface was pushed

more quickly up the riser, generating increasing back pressure due to the increasing

liquid head. The flowline remained essentially full of liquid until the second shutdown.

7.5 Partial displacement of riser contentsIn parallel with the work on the pressure data, a procedure was developed and carried out

to inject methanol into the base of the riser through existing connections into the RBGL

system. This addition of liquid was intended to displace existing liquid out of the top of

the riser to allow sampling and testing in order to determine the nature of the fluids in theriser. About 150 m at the top of the riser was found to contain oil, with the rest of the

riser being filled with seawater.



12/17

7.6 Identification of source of seawater ingress, and movement of seawaterFrom the pressure data, the liquid ingress rate was estimated as 2-3 m3/hr. Using the

flexibility of the overall subsea system valving, it was possible to isolate sub-sections of

the flowline to watch for pressure change, and then either depressurise slightly, or re-

pressurise (by addition of methanol). A sub-section was found in which the pressure

would rise up to the external seawater head. Eventually a small seawater flow path wasidentified, through an incorrectly installed clamp covering a vent port on a future tie in

slot on one of the manifolds. Records had documented a difficulty during assembly.

The ingress was then possible through this flow path because the connected umbilical

core pressure for a time had not been maintained above ambient seawater pressure.

On initial entry into the flowline, this seawater had 3.4 km of oil above it in the flowline

section towards the riser, and a small amount of oil (up to 0.5 km) above it in the section

towards M2-2. As the water continued to flow in, the oil-water interfaces moved

towards the riser base and M2-2 respectively.

7.7 Cause of high riser base pressureOn the re-start of production after the extended shutdown, roughly 3.2 km of oil waspresent in the flowline leading up to the riser base, with oil already ~0.2 km up the riser.

The remainder of this 6 km flowline section contained seawater (2.9 km). As production

re-started the oil was pushed up the riser, eventually completely filling the riser, leading

to the riser base pressure of 140 bar, and then producing oil into the process plant. The

oil-water interface, initially some 3.2 km back in the flowline, was pushed towards the

riser base, taking some 90 minutes to arrive.

When the oil-water interface reached the riser base, seawater began to enter the riser.

Given the higher density of seawater compared to the oil, the overall liquid head in the

riser started to increase. For a riser completely full of seawater, the dP would be ~130bar. Given that the operators shut down the system when the riser base pressure was 159

bar (a dP of 127 bar), this is consistent with the findings of the displacement of riser

contents, that the oil - water interface had reached to ~150 m from the top of the riser.

The oil-water interface had therefore moved some 4.5 km during the re-start.

7.8 Established sequence of eventsIn summary, the established sequence of events is as follows:

flowline-riser 2 was shut down, with depressuring of riser top to 28 bar ~4 km of crude oil collected in flowline, with a gas pocket trapped upstream

seawater slowly entered the subsea system, filling many kilometres offlowline

at production re-start the gas-oil interface was some 0.2 km up from the base ofthe riser, and the oil - water interface some 3.2 km back down the flowline

production was re-started, moving these interfaces forward the gas-oil interface reached the process, and oil began to be produced the riser was full of oil until the oil-water interface reached the base of the riser

some 90 minutes after production re-start

the oil-water interface progressed up the riser, increasing the riser basepressure, followed by operator initiated shutdown that happened to be when the

oil - water interface was only 150 m from the top of the riser



13/17

8 PREPARATION FOR RE-OPENING OF SIVGiven the understanding developed above, there was a very high degree of confidence

that the riser was not affected by any sort of blockage, and so plans for reopening the

SIV and then re-starting production again could be made.

8.1 Investigation of possible trapped gas volume in flowlineJust after the second shutdown, the dP between the riser base and M2-1 was ~10 bar,

consistent with being essentially liquid filled, with a high proportion of water. However,

given the uncertainty as to the proportions of oil and water in that section of the flowline,

and uncertainties in the movement of gas after the production re-start, it was not possible

to state categorically that the line contained no gas. This left the potential for there to be

a gas pocket trapped upstream of the SIV. The length of any such gas pocket could have

been in the order of a few tens of metres, given the uncertainties because the riser base

pressure measurements were downstream of the SIV.

If there was any gas trapped upstream of the SIV, it would be at or close to the flowline

pressure at the time of shutdown (159 bar). This led to two possible issues on opening

the SIV, as a function of the position of the riser top boarding valve.

8.2 Potential for hydrate formation on opening SIVGiven that the riser was almost full of seawater at the time of the second shutdown, it

was very likely that on opening the SIV any gas pocket would mix with the seawater and

form hydrate. Two measures were taken to protect the riser against this. Firstly,

additional methanol was injected into the riser base via the gas lift system to inhibit the

seawater (although uncertainties in mixing, and the possibility of some bypassing, were

noted). Secondly, in order to protect the length of riser under the point of entry of thegas lift system down to the SIV, a sufficient volume of TEG was injected to displace that

volume. Two injection locations were utilised - firstly, through the gas lift system

chemical supply line previously used for methanol, and secondly through a 50mm drain

valve immediately downstream of the SIV that was accessed by ROV.

8.3 Potential for high pressure gas movement on opening SIVIf the riser top valve remained shut, then on opening the SIV any gas pocket would

proceed up the riser but be constrained to constant volume. The pressure of this volume

on arrival at the riser top would therefore still have been ~160 bar, and in turn the

pressure at the riser base would then have been ~290 bar (but well within the maximum

operating pressure). This high gas pressure would have required careful depressurisation

and variations from the normal topsides operating procedures, given the significant J-T

cooling from this pressure.

If the riser top valve was left open, then on opening the SIV the gas would have moved

up the riser, expanding (because of the decreasing liquid head above it) to slug-catcher

pressure, and could have generated a substantial liquid and gas surge into the process.

The latter option was selected, but with the mitigation measure of setting the riser top

valve partially open in order to throttle back any liquid production. This was backed up

by OLGA simulations of movement of a potential gas pocket sitting upstream of the SIV,looking at a conservative gas pocket size.



14/17

9 ANALYSIS OF SYSTEM STATUS AFTER SECOND SHUTDOWNIn order to complete the understanding of the status of the system after the second

shutdown, it was necessary to attempt to reconcile the amount of production of oil and

gas into the system between the re-start and the second shutdown with the gas-oil and

oil-water interface movements. This was by nature a qualitative effort with a number ofuncertainties to be taken into account. All numbers are indicative only.

9.1 Upstream gas volume in flowlineOn the original shutdown with oil at the low point in the flowline, there was a gas

volume (~5.5 km) trapped upstream from M2-1 to M2-3, at a lowest pressure of 35 bar.

As the seawater entered and the pressure rose (reaching ~70 bar just prior to opening the

riser top boarding valve and production re-start) this gas volume was compressed to ~2

km (accounting for compressibility, but assuming no gas went back into solution, given

the lack of mixing). With 0.5 km of oil already present, 3.5 km of water had been added.

As production re-started, and oil was pushed up the riser, the back pressure on this gasmass increased to ~160 bar, further reducing its length to ~1 km. Additional gas and oil

(see next section) were also being added at M2-3, M2-1, and M2-2. Production from

M2-3 was into the gas filled region, and from M2-1 into seawater filled flowline.

9.2 Reconciliation of production data with measured fluid volume availableGiven previous calibration of choke settings to production rates, estimates were made

(Table 2) of the fluids added at M2-1, M2-2, and M2-3 after the re-start. Given the

combination of pressure changes and gas added (~1 km), the upstream gas bubble length

on second shutdown was estimated as ~2 km (again assuming no gas produced goes back

into solution on cooling). The oil added at M2-2 / M2-3 occupied 1.8 km, and at M2-1

2.5 km, and the gas at M2-1 ~1.2 km. Total fluids added would have occupied ~6.5 km.

The volume available to contain the production was estimated from the distance the

downstream oil-water interface moved (~4.5 km, section 7.7), combined with the volume

available due to the compression of the original trapped gas from 70 to 160 bar (~1 km).

Given the fluid mass added and the pressure and temperature conditions prevailing in the

flowline it became clear that the total gas and oil volumes produced were greater than

that apparently available by approximately the volume of gas produced at M2-1.

As mentioned in the preceding section, the production fluids at M2-1 flowed into a

seawater filled line, with almost 2 km of seawater passing M2-1 during their production.

Given the high pressure and low temperature of the seawater, it is virtually certain that

all of the gas produced into the system at M2-1 would have formed hydrate, thereby

occupying virtually the same volume as the water converted. This is supported by the

rough reconciliation of the production volumes with the available space in the flowline.

9.3 Final understanding of fluid locations prior to re-opening SIVDuring the analysis to determine the nature and location of the fluid ingress, a number of

further changes to system inventory and pressures were made. There were two small

depressurisations of gas at M2-3, and several additions of methanol (used to assess and

confirm the remaining gas volume by observation of the pressure increase due to

addition of a known volume of liquid).



15/17

10 RE-OPENING OF SIV10.1 Pressure conditions prior to the re-openingAt this time the pressure at the riser base was 130 bar, and near the flowline low point at

M2-1, 160 bar. For a liquid filled flowline (as inferred from the line condition just after

the second shutdown, and subsequent methanol additions) this would imply a pressure of~150 bar immediately upstream of the SIV. The expected pressure differential across the

SIV was therefore 20 bar. With the riser top boarding valve closed, the opening of the

SIV was expected to result in a measurable pressure increase at the riser top.

10.2 Effect of re-opening the SIVHowever, on reopening the SIV there was no change to the riser top, riser base or M2-1

pressure measurements. There was now a pressure retaining blockage in the flowline

somewhere between M2-1 and the riser base.

10.3 Assessment of fluid/blockage conditions in the flowlineGiven that the system was flowing, without excessive frictional pressure drop, prior tothe second shutdown, there was no discernible blockage at that time. During the weeks

between that shutdown and the reopening of the SIV, the mixture (some 3-4 km in

length) of hydrate, oil, and seawater (and possibly emulsion), resulting from the

production of fluids at M2-1 into seawater, had formed a pressure retaining blockage.

11 REMEDIATION ACTIVITIES11.1 Assessment of depressurisation optionsGiven the high likelihood of the presence of hydrates in the blockage, several

depressurisation options were investigated. The starting point was for depressurisation atboth ends of the flowline, as per standard practice with hydrate blockages to avoid the

risk of sudden and rapid movement of the blockage constituents.

Riser base gas lift was available to lift liquid out of the riser to depressure the

downstream end of the flowline. The upstream end of the flowline could be

depressurised either back to the host, or to a vessel through a work over riser at M2-1.

The option of single-ended flowline depressuring by gas lifting liquid out of the riser was

also considered. This became the primary option as it was possible to isolate the

flowline at M2-1, with the section from M2-1 to the riser base largely free of gas, as per

discussions earlier in the paper. Therefore in the event of blockage release there was no

driving force, due to the absence of upstream pressurised gas in that section.

11.2 Detailed consideration of single-ended flowline depressurisationThis option was worked extensively, given the potential for some small gas pockets to be

in the line. Calculations were done to estimate possible fluid movements for various gas

pocket locations and sizes. Even for a blockage close to the riser base, with a gas pocket

immediately upstream, there was a known minimum length of 150 m of liquid between

the SIV and the gas lift injection wye that would be ahead of any moving hydrate plug.

The mass of this liquid was sufficient to limit any possible acceleration. The conclusion

was that this option, in this particular set of circumstances, was acceptable.



16/17

11.3 Using riser base gas lift to depressure the flowlineA procedure was developed to use cycles of gas flow rates to lift the seawater/methanol

mixture out of the riser. The first rate would be applied through to a steady state riser

base pressure and then shut off, allowing any residual liquid in the riser to settle out.

Then the second rate would be applied, shut off, and then finally the third cycle would be

carried out. OLGA modelling carried out prior to the procedure gave confidence that thedepressurisation procedure would be successful.

The maximum lift gas volume flow rates used in the first two cycles were 425 and 481

SMm3/d. OLGA predictions of the effect of this gas lift on residual liquid content in the

riser, and the actual measured amounts, are given in Table 3. Slight repressuring of the

riser was done after each cycle to manage J-T effects in the riser base gas lift system.

After the second cycle, the pressure at the base of the riser was 15 bar. The pressure at

M2-1 remained at ~170 bar, giving a pressure differential of >150 bar across the

blockage. Figure 12 shows that on initiation of the third gas lift cycle the blockage then

released, with no discernible fluid movement, and RB-M2-1 dP settled out at ~10 bar.

Depressuring using riser base gas lift

0

20

40

60

80

100

120

140

160

180

200

06:00 09:00 12:00 15:00 18:00 21:00 00:00

P

ressure

-bar

55 bar dP

First RBGL cycle

Second cycle

Methanol injection at S4 raises pressureSteady pressures, with no

communication S4-riser base(fluid filled would be 10 bar)

Pressure communicationreestablished, 15 mins after thirdRBGL cycle, and after 4 hours at

>100 bar dP

10 bar dP, liquid head

(RBGL)

Third cycle

dP >100 bar

M2-1 - RB

M2-1

RB

at M2-1 raises pressure


0

20

40

60

80

100

120

140

160

180

200

06:00 09:00 12:00 15:00 18:00 21:00 00:00

P

ressure

-bar

55 bar dP

First RBGL cycle

Second cycle




>100 bar dP


(RBGL)

Third cycle

dP >100 bar


0

20

40

60

80

100

120

140

160

180

200

06:00 09:00 12:00 15:00 18:00 21:00 00:00

P

ressure

-bar

55 bar dP

First RBGL cycle

Second cycle




>100 bar dP


(RBGL)

Third cycle

dP >100 bar

M2-1 - RB

M2-1

RB

at M2-1 raises pressure

Figure 12 - Effect of riser base gas lift on riser base and M2-1 pressures

Interpretation of this may be either of a very small hydrate blockage that dissociated

quickly to equilibrate the pressure, or a longer length of viscous oil/ hydrate/ seawater/

emulsion mixture through which a pressure wave slowly propagated given the high dP.

11.4 Flow line displacement and return to serviceOnce pressure communication was re-established the flowline was displaced with dead

crude and returned to service.

Table 1 - Steady state flowrates (for flowline - riser systems 1 and 2)

FR

1

Oil

rate

Sm3/d

Gas

rate

SMm3/d

Water

rate

Sm3/d

FR

2

Oil

rate

Sm3/d

Gas

rate

SMm3/d

Water

rate

Sm3/d

M1-4 1956 313 0 M2-3 3275 928 0

M1-3 5030 655 254 M2-2 2385 404 295M1-2 2633 292 70 M2-1 4293 684 0

M1-1 2339 357 231



17/17

Table 2 - Flowline - riser 2 fluid added during re-start

Gas, kg at

140 bar, 80C

Gas, km at

140 bar, 4C

Oil, kg at

140 bar, 80C

Oil, km

at 140 bar, 4C

M2-2+M2-3 5900 0.9 85000 1.8

M2-1 8100 1.2 117000 2.5

Table 3 - OLGA predictions of riser emptying

Riser base gas lift cycle

maximum flowrate

Predicted

liquid left, m

Measured liquid

left, m

425 SMm3/d (15 MMscfd) 47 177

481 SMm3/d (17 MMscfd) 18 54


bhr multiphase conf - steady-state and interrupted production in deep water oil system

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