97DOI 10.1007/s12182-013-0255-8

Li Wenqing1, Gong Jing1 , Lü Xiaofang1, Zhao Jiankui2, Feng Yaorong3 and Yu Da1

1 Beijing Key Laboratory of Urban Oil and Gas Distribution Technology, China University of Petroleum, Beijing 102249, China2 China National Oil and Gas Exploration and Development Corporation, Beijing 100034, China3

Abstract: The natural gas pipeline from Platform QK18-1 in the southwest of Bohai Bay to the onshore processing facility is a subsea wet gas pipeline exposed to high pressure and low temperature

management of the subsea pipeline.

Key words:

A study of hydrate plug formation in a subsea natural gas pipeline using

*Corresponding author. email: ydgj@cup.edu.cn

1 Introduction

gas is transported in subsea pipelines at low temperature and high pressure. The low temperature and high pressure conditions may cause natural gas and water transported in the pipelines to form gas hydrates. Upon formation, hydrate accumulation and agglomeration eventually form a slug,

more attention has been paid to developing flow assurance

and Gudmundsson, 1999; 2006; Gaillard et al, 1999; Gudmundsson and Graff, 2003; Ning et al, 2007; Wang et

et al, 2010a; 2010b; 2010c). Unfortunately, little research is focused on the phenomena involved in a hydrate plug

to provide an estimate of where and approximately when a hydrate plug may form in collaboration with the SPT Group.

hydrate formation model and to investigate the effect of experimental variables on the plugging behavior of hydrate formation in water-in-oil emulsions. Davies et al (2010) developed a model to predict hydrate plug formation by studying the mass and heat transfer resistances to hydrate formation in oil-dominated systems, and the revised hydrate formation model had been validated on both laboratory and industrial scales. Emmanuel et al (2008) presented the effects

crude oil systems by conducting tests in the flow assurance

conditions. Test results indicated that the plugging behavior of oil system is dependent on these variables and the oil-water chemical properties. Nevertheless, up to now there seldom

into real plugging practices, and the results are also system

meaningful to perform relevant studies based on real hydrate

Pet.Sci.(2013)10:97-105

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In the southwest of Bohai Bay, the subsea gas pipeline between the QK18-1 central platform and the onshore natural

transported was wet gas containing light hydrocarbon and vapor, and the flow rate was about 9,500 Sm3/h. The operation temperature and pressure of the pipeline was 5-45

there was something wrong in the pipeline between Platform QK18-1 and the Boxi processing plant. The inlet pressure

sharply. Through adjusting the inlet and outlet pressures and the injection of methanol both upstream and downstream,

flow rate and the pressure fluctuated rapidly (the transient 3

conditions, it was inferred that three reasons may have led to the increased inlet pressure, which are listed as follows:

1) There were hydrate plugs in the subsea pipeline.

the pressure drop along the pipeline increased.

no pig lost in the pipeline, but in the processing plant a great

experimental research is done to further investigate hydrate plug formation in gas transportation pipelines.

2 Theoretical and experimental analyses of gas samples

To determine phase distribution in the pipeline, three gas

Platform QK18-1, and their compositions are listed in Table 1. The phase envelope of the gas mixture was obtained from the

1976) and four calculated values were verified from experimental data, as shown in Fig. 1. This indicated that the calculated results were in good agreement with experimental results. Therefore, the phase envelope may be used to predict the phase state of the gas mixture transported in the gas pipeline under various operating conditions. Due to the fact that the natural gas under pipeline operating conditions

similar to the problem encountered in the West-East Gas Pipeline described in 2005 (Zhao et al, 2009).

so the gas (methane) in the pipeline might combine with water to form hydrates under specific thermodynamic conditions. In our laboratory, a sapphire autoclave was used to investigate whether the reaction occurred and hydrate formation conditions were measured using an isothermal pressure search method.

The two-step hydrate formation mechanism proposed

by Chen and Guo for gas hydrate formation was adopted as the conceptual picture. The first step is the formation of

reaction and the second step is the adsorption of gas

The natural gas hydrate formation curve was predicted by the Chen-Guo model (Chen and Guo, 1996; 1998).

Fig. 3 showed that the simulation results were in good agreement with experimental values. This model could be used to predict formation conditions of hydrates in the subsea

pressure and temperature values along the pipeline were simulated. Then, the hydrate formation pressure values at simulated temperatures of each pipeline section were calculated from the Chen-Guo model, as shown in Fig. 4. The results indicated that most of the simulated pressures were above the hydrate formation pressure. So if any free water existed in the pipeline, gas hydrates would be formed. Therefore, it was reasonable to ascribe the cause of this

Fig. 1

-160 -140 -120 -100 -80 -60 -40 -20 0 20 40 600

2

4

6

8

10

12

14

Calculated values Experimental data

Pre

ssur

e, M

Pa

Temperature, °C

Table 1 The composition of gas samples

ComponentSample

S1 S2 S3

C1 87.1 86.6 87.0 86.9

C2 6.06 5.86 6.09 6.00

C3 3.23 3.20 3.36 3.26

i-C4 0.634 0.644 0.655 0.644

n-C4 1.11 1.12 1.15 1.13

i-C5 0.33 0.277 0.343 0.317

n-C5 0.249 0.256 0.217 0.241

C6 0.264 0.37 0.315 0.316

CO2 0.716 0.653 0.735 0.705

N2 0.307 1.02 0.135 0.487

Sum 100 100 100 100

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It provided online monitoring of the evolution of objects (droplets, bubbles and solid particles) transporting inside

been described elsewhere (Pauchard et al, 2007; Boxall et

which was ahead of the inlet of the test loop. The window

estimate the initial water droplet (Dp

to follow the hydrate particle agglomeration with time. The

to longer chord length and it was particularly well adapted to agglomeration phenomena.

3.2 Fluids

gas pipelines in all tests. The dry gas composition is listed

3, with

from the Chen-Guo model is shown in Fig. 6.

3.3 Experimental procedures

as much as possible, hydrate formation and plug formation tests were performed at a constant pumping speed and a constant static pressure. The experimental procedures are as follows.

3

content was injected into the separator. The flow loop

Fig. 5

Compressor

Magnetic centrifugal pump

Gas supply

Separator

Buffer tank

Chiller

Mixer

JacketFt01

P06

P01

P07P03 T03

DP03

T04

P02

P04

T05

DP01

DP02

DP4

T06T01 T02

T08 Ft02FBRM prob

(up-flow of dip section)

Depressuring valve

Ft03

Sight glassSight glass

NDR1

NDR2

Instrument codesP: Pressure transducerDP: Differential pressureT: Thermometer

NDR: Nuclear densitometerFt: Mass flow meter

Gas charge line

Liguid charge line

T07P05

Gas supply line

Coolant bath

Coolant bath

Coolant bath

Coolant bath

Fig. 6

0 5 10 15 20 25 30 350

5

10

15

20

25

Pre

ssur

e, M

Pa

Temperature, °C

natural gas under these conditions.2) The gas-saturated water/oil mixture was circulated at a

3) Under constant pressure and constant flow rate (850

cooling-down period, gas was forced into the separator from

4) In the hydrate formation process, the temperature,

and recorded in real time. In this study, P05 and T05, shown in Fig. 5, were chosen as the pressure and temperature points

Pet.Sci.(2013)10:97-105

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2004), and the blockage time (tbTb

T

T and Tb

Table 3 Te, T , Tc and Tb

kg/hTe

ºCteh

T ºC

th

Tc

ºCTb

ºCtbh

t and blockage

Table 2

N2

CO

CO2

C1

C2

C

C4

C

C

Te), then T

Tb

Te to TT to Tb T to Tb

Tb

Te to Ttime tin Tc

T Te

102

time tb

Fig. 7

0 5500 11000 16500 22000 27500 33000 38500 44000 49500 550002.0

2.5

3.0

3.5

4.0Pressure

Temperature

Density

Flow rate

Pre

ssur

e, M

Pa

Time, s

2

4

6

8

10

12

14

16

18

20

Tf

TbTf

Tem

pera

ture

, °C

Hydrate formation equilibrium temperature at 3.2 MPa

Te

600

630

660

690

720

750

780

810

840

870

900

Den

sity

, kg

/m3

0

100

200

300

400

500

600

700

800

900

1000

Flo

w ra

te, k

g/h

Fig. 8

0 2750 5500 8250 11000 13750 16500 19250 22000 24750 275002.0

2.5

3.0

3.5

4.0

4.5 Pressure

Temperature

Density

Flow rate

Pre

ssur

e, M

Pa

0

2

4

6

8

10

12

14

16

18

20

Hydrate formation equilibrium temperature at 4.1 MPa

600

630

660

690

720

750

780

810

840

870

900

Tf

Tb

Tf

Te

0

100

200

300

400

500

600

700

800

900

1000

Flow

rate

, kg/

h

Den

sity

, kg/

m3

Tem

pera

ture

, °C

Time, s

Fig. 10

1250

1000

750

550

250

0

110

1001000 00:00:00 02:05:00 04:10:00 06:15:00

Cou

nts

(No

wei

ghte

d)

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 200002.0

2.5

3.0

3.5

4.0

4.5

Flow

rate

, kg/

h

Tem

pera

ture

, °C

Pressure

Temperature

Flow rate

Pre

ssur

e, M

Pa

Time, s

0

2

4

6

8

10

12

14

16

18

20

400

600

800

1000

1200

1400

1600

1800

2000

2200

Tf

hydrate formation equilibrium temperature at 4.1 MPaTe

Fig. 9

Fig. 11

200

150

100

50

00:00:00 01:00:00 02:00:00 03:00:00 04:00:00 05:00:00 06:00:00 07:00:00

104

Fig. 12

(a) Before hydrate formation

(b) Hydrate formation

(c) Hydrate plug formation

2