THE EFFECT OF DRILLING FLUID INVASION ON THE GAS HYDRATE-

BEARING SEDIMENTS

Fulong Ning,Yibing Yu, Ling Zhang, Guosheng Jiang

Faculty of Engineering

China University of Geosciences

Wuhan, Hubei, 430074

China

Keni Zhang

Earth System Division

Lawrence Berkeley National Laboratory

1 Cyclotron Road, MS 90-1116, Berkeley, California, 94720

United States

ABSTRACT

When drilling through the oceanic gas hydrate-bearing sediments, the water-based drilling fluids

under overbalanced drilling condition would invade into the borehole sediments and make gas hydrates unstable. This behavior will further influences the wellbore stability, drilling safety and

well logging interpretation and evaluation. In this work, using TOUGH+HYDRATE V1.0 which

developed by the Lawrence Berkeley National Laboratory, we performed the numerical simulations to study the effects of density (i.e., corresponding pressure), temperature, salt content

of drilling fluids and the permeability of sediments on the hydrate stability around borehole. The

results show that the drilling fluid invasion will enhance greatly the hydrate dissociation near wellbore sediments if the temperature of drilling fluids is higher than that of hydrate stability.

When the temperature and salt content of drilling fluids are constants, the higher the pressure of

the drilling fluid is, the greater degree of invasion and hydrate dissociation are. The gas and water produced from hydrate dissociation can re-form again at the certain depth in the radial sediments,

and even the hydrate saturation in this place is higher than that in situ sediment due to the

displacing effect of the drilling fluid invasion, which forms a high-saturation hydrate girdle band around the borehole. Under the same temperature and pressure of drilling fluids, the higher the

salt concentration of the drilling fluid, the faster rate and greater degree of hydrate dissociation

due to the stronger thermodynamic inhibition effect and heat transfer efficiency. The appearance of high-saturation hydrate girdle band mainly depends on the temperature and salinity of drilling

fluids. Our simulations conclude that in order to keep wellbore stability and well logging

accuracy during drilling through the hydrate-bearing sediments, it is better to adopt the managed pressure drilling and low-temperature mud circulation, and add kinetic inhibitors or anti-

agglomerants instead of salts into drilling fluids for preventing hydrate re-formation in the well.

Keywords: gas hydrates, drilling fluid, invasion, secondary hydrates well logging, wellbore

stability

Corresponding author: Phone: +86 18963963512 Fax +86 2767883507 E-mail:nflzx@cug.edu.cn

This work was supported by National Natural Science Foundation of China (No.50704028,40974071,U0933004), Guangzhou Center for Gas Hydrate Research, Chinese Academy of Sciences (No.o807s2) and the Fundamental Research Funds for the Central Universities (No. CUGL100410).

Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011),

Edinburgh, Scotland, United Kingdom, July 17-21, 2011.

INTRODUCTION

Gas hydrates are non-stoichiometry inclusion

compounds which formed when small (<0.9nm) gas molecules (guest molecules) contact water

(host molecules) under low temperature

(typically<300K) and high pressure (typically >0.6MPa) [1]. As host molecules, the

water molecules form water cages by hydrogen

bonds then trap the guest small gas molecules, the latter usually are methane and carbon dioxide

molecules, which can help to maintain the cage’s

stability [2-3]. Thus, gas hydrate is also know as the natural gas hydrate, or simply as hydrate.

There are three common types of gas hydrate

structure: sI hydrate, sII hydrate, and sH hydrate. Although there are other structure types such as sT

type and half hydrate cagelike hydrate [4-7], but so

far they exist only in the laboratory. In the nature environment gas hydrate are mainly sI and sII type

hydrate, later sH type hydrate was also confirmed

that exist in nature, as in the Gulf of Mexico and Cascadia Margin [8-9]. Since the 1960s and 1980s

gas hydrate was found in permafrost and marine

area respectively [10-11], more and more governments, oil and gas companies and kinds of

academic research institutions had paied enormous

attention on it, for its important significance in the resources, environment and global change. Gas

hydrate research has become one of the hot spots

in the geosciences and energy field. As a result, the knowledge of gas hydrates achieved an

explosive growth [12], its research field has been

spreaded from the initial flow assurance for preventing the block in the oil and gas pipeline

[13-14] to resource potential[15-17], safe

drilling[18-19], geologic hazard[20], carbon cycle[21] and climatic change[22-23], even the

outer space hydrate[24-25]. Recently, the National

Energy Technology Laboratory of United States Department of Energy has made a remarkable

progress in rapid forming gas hydrate [26], which

bring an attractive application prospect for the hydrate technology to use in nature gas and

hydrogen storage and transportation [27-29], CO2

capture and geological burial[30], gas separation[31], cold-storage[32] and desalination

of sea water[33]. So to some extent the gas hydrate research has reflected a country’s comprehensive

scientific and technological competition and

sustainable development potential [34]. Enter the 21st century, with the reduction of

recoverable oil and gas and their consumption

increases, unconventional energies such as nature

gas hydrate and shale gas exploration and

exploitation were officially put on the agenda.

However, controlled by the hydrate reservoir-forming conditions, the nature gas hydrates mainly

occur in the oceans, permafrost and some deep-

water sediments of inland lakes [22], where has rugged environment and seriously lacked

infrastructure. Therefore, the exploration and

exploitation of hydrates are far more difficult than those of conventional oil and gas reservoirs. In the

marine areas, gas hydrates account for the vast

majority of the amount of gas hydrates that have been found [35]. They distribute in the upheaval of

active and passive continental margin and mainly

are methane hydrates. According to Klauda and Sandler [36], there was 74,400 Gt of CH4 trapped

in hydrates buried in marine zone, which were

three orders of magnitude larger than worldwide conventional natural gas reserves. Therefore, the

exploration and exploitation of marine gas

hydrates become a hot topic for present and future energy research. And now the commonly methods

used for hydrate exploration include geophysical,

geochemical and core-drilling. The first is the most widely used [37]. Normally it includes

seismic detection technology[38], logging

technology[39] and the newest marine electromagnetic technology[40]. The core-drilling

is the most direct way for the hydrate reservoir s

identification and evaluation. So far, marine hydrate drilling activities have mainly operated in

Blake Ridge[41], Hydrate Ridge in Cascadia

Continental Margin [42], Gulf of Mexico[43], Nankai Trough [44], Northern Slope of South

China Sea [45], Indian continental margin[46], the

Ulleung Basin in the East Sea of South Korea[47]. As the marine hydrate deposits are less

consolidation [48-49], it would result in wellbore

instability if the under-balanced drilling technology is adopted. Further more, under the

under-balanced drilling condition, gas hydrates

will decompose because of pressure decline and cause a sharp strength decrease of the

sediments[50-51], which would increase the risk

of wellbore instability. For this reason, the suitable way is to maintain the wellbore pressure larger

than the pore pressure but lower than fracture pressure when drilling in hydrate bearing sediment

s [52]. On the condition mentioned above, drilling

fluid(here referring to water-based drilling fluid) will displace the original pore fluid surrounding

the borehole and invade into the sediments

because of pressure difference. Drilling practice

has proved that properties of the sediment around

borehole are changed when drilling fluid invasion,

such as strength and pore pressure [53]. When drilling fluid invasion occurs in hydrate-bearing

sediments, the process likely is coupled with

hydrate dissociation induced by the temperature of drilling fluid and the generation of heat by drilling

tool’s friction. This is the mainly different from

what the invasion take places in conventional oil and gas sediments. Moreover, among numerous

geophysical logging properties, the resistivity and

wave velocity of sediments are influenced greatly by gas hydrates occurrence [39,54-57]. In marine

areas, hydrate bearing sediments are usually

underconsolidated, while acoustic wave is influenced more greatly by consolidation than

other logging methods, so resistivity well logging

is more reliable than acoustic and other logging methods[58-59]. However, the circulation and

invasion of drilling fluid have a significant

influence on the resistivity well logging [60]. For the inhibition of hydrate formation in the wellbore

and the protection of the marine environment,

water-based drilling fluid system containing polymer and high concentration of salts are

commonly used while drilling in deep water [61].

But the invasion of drilling fluid with high salinity will seriously affect the reservoir characteristics

and the accuracy of the resistivity logging. Also

the salts are thermodynamic inhibitors, with the invasion of drilling fluid they will cause hydrate

dissociation and further influence the identify and

evaluation of logging, wellbore stability and the security of borehole. Therefore, the investigation

of dynamic characteristics of the water-based

drilling fluid invasion coupled with hydrate decomposition and the influence for the formation

is of great significance and value for the response

of logging in hydrate sediment, evaluation of reservoirs, borehole stability, regional hydrate

resources and environmental assessment and the

hydrate dynamic observation system implementation in the well for the Integrated

Ocean Drilling Program(IODP).

Under over-balanced conditions, the temperature and salinity of drilling fluid are the major factors

to determine the hydrate stability or not in the sediments during the invasion process. If

temperature of drilling fluid is equal or lower than

the hydrate equilibrium temperature (Point A in Figure 1) under the same salinity and pressure

conditions, the mechanism of drilling fluid

invasion in hydrate bearing sediments is similar to

that in conventional oil and gas reservoirs.

Compare to permafrost areas, the temperature of

oceanic hydrate-bearing sediment is higher and closer to the phase equilibrium line. For example,

in the Shenhu area of South China Sea, the

temperature and pressure of hydrate bearing sediments are nearby the boundary of phase

equilibrium [17]). Besides, drilling tool’s friction

can generate heat and the presence of thermodynamics inhibitors in drilling fluid can

drop the equilibrium temperature of gas hydrates.

So these factors act together likely cause that the temperature of drilling fluid is higher than the t

phase equilibrium temperature under the same

condition(Point B in Figure 1), then the hydrate dissociation would occur around the borehole.

That is to say, drilling fluid invasion coupled with

hydrate dissociation often encounters when drilling through the marine hydrate-bearing

sediments.

Figure 1 The relations between the temperature of

drilling fluid and the temperature of reservoir If ignore the minor factors, the main behaviors of

drilling fluid invading into hydrate-bearing

sediment can be described in the multi-phase flow of drilling fluids displacement induced by

differential pressure and the hydrate dissociation

induced by differential temperatures (between the temperature of drilling fluid and the temperature

for hydrate phase equilibrium). So the dynamic

invasion process coupled with hydrate dissociation can be approximately described as a opposite

direction flow process of hydrate exploitation by

pressure reducing and heat stimulating the hydrate reservoirs. We can use the existing numerical

models for gas production from hydrate

dissociation to investigate the invasion process of drilling fluid in the hydrate-bearing sediments.

Merely the influence of invasion is smaller and

P

T

The hydrate phase Equilibrium in the drilling fluid system

Temperature of drilling fluid

Pf A

B

The hydrate phase equilibrium boundary in the in-

situ sediment

Temperature of the sediment

limited in an annular area around the borehole, and

the hydrate dissociation also occur within a certain

range around the borehole. Here, on the basis of the previous theoretical analysis and numerical

simulations [62-63], we further simulated the

characteristics of drilling fluid invasion and the influence on hydrate sediments around borehole

by the TOUGH+HYDRATE code which was

developed by Lawrence Berkeley National Laboratory [64].

NUMERICAL MODELS

Simulation method

The software, TOUGH＋HYDRATE, is mainly

used to simulate the gas recovery from hydrate

reservoirs in marine or permafrost regions[65-67], which can be also used with other softwares (e.g.

FLAC 3D) to simulate the wellbore stability and

the sediment deformation during gas production from gas hydrates[68-69]. The model of this

software is developed from the general

groundwater seepage simulator (TOUGH V2.0) by combining with equation of hydrate state

(EOSHYDR). TOUGH+HYDRATE can model

nonisothermal hydration reactions, phase behavior, and flow of fluids and heat under the conditions

typical of naturalCH4-hydrate deposits in complex

geologic media. It includes both an equilibrium and a kinetic model of hydrate formation and

dissociation [64]. The model accounts for heat and

up to four mass components (i.e., water, CH4, hydrate, and water-soluble inhibitors such as salts

or alcohols) that are partitioned among four

possible phases: gas, aqueous liquid, ice, and hydrate. A total of 15 states (phase combinations)

can be described by the code, which can handle

any combination of hydrate dissociation mechanisms and can describe the phase changes

and steep solution surfaces typical of hydrate

problems [70]. Here we adopted the equilibrium model of hydrate formation and dissociation, and

did not consider the chemical and mechanical

coupling and diffusing effect. At the same time, we assumed that the drilling fluid only contained

the thermodynamic inhibitor NaCl and the

sediment was isotropic, so that the invasion

problem was simplified as a one-dimensional

radial displacement problem.

Simulation parameters The cylindrical coordinate was adopted for the

simulations. The well has a diameter of 150mm

and lies at the center of the cylinder, and the drilling pole diameter is assigned a value 90mm,

so the annular space is 30mm. The range of study

here is 3m around the borehole. Then a thin layer with a thickness of 0.1m was taken from the center

of the hydrate bearing sediments, and it was

divided into 90 elements along the radial direction. The drilling fluid in the annular space was treated

as one element, which was set as a fixed internal

boundary, i.e., the temperature and pressure of drilling fluid in this place kept constant (Figure 2).

The in-situ temperature and pressure were set at

8C and 10MPa, which met the condition of hydrate stability in the sediment. The drilling fluid

had a temperature of 15C and a pressure of 12

MPa. The conductivity of marine sediment

(saturated by water) is set 3.1 W.m-1

. C -1

, and the conductivity of marine sediment (without water) is

0.85 W. m-1

.C -1

. Under the initial condition, the hydrate bearing sediments contained two phases,

hydrate phase and liquid phase. The hydrate

saturation is 50% (vol) and the liquid saturation is also 50% (vol). The density of the marine

sediment is about 2600kg/m3, the porosity is 35%,

and the permeability coefficient is 2.96×10-13

m2.

The primary parameters and physical properties of

the sediments in the simulations were shown in Table 1.

Figure 2 A schematic of drilling fluid invasion

during drilling in the hydrate-bearing sediment

Parameters Values Parameters Values

Initial Temperature(Ts) 8C grain density (ρs) 2600kg/m3

Initial Pressure(Ps) 10MPa grain Specific Heat(Cs) 1000J.kg-1. C -1

Pore water salinity(Xw) 3.5% Wet conductivity of sediment(saturated

water) (λs) 3.1 W. m-1. C -1

Hydrate saturation in situ(SH) 0.5 Dry thermal conductivity (no water) (λHs) 0.85 W.m-1. C -1

Pore water saturation in

situ(SA) 0.5 Thermal conductivity of hydrate(λH) 0.5 W. m-1C -1

Temperature of drilling

fluid(Tm) 15C intrinsic permeability (K) 2.96×10-13m2

Pressure of drilling fluid (Pm) 12 MPa hydrate Density (ρH) 920kg/m3

Porosity(φ ) 0.35 Specific Heat of hydrate(CH) 2100J.kg-1. C -1

Table 1 Parameters of formation in simulation

RESULTS AND DISCUSSIONS

Time-dependent geophysical properties during

the invasion of drilling fluid From Figure 3 and 4, it can be found that when the

borehole in the gas hydrate-bearing sediment is open, the drilling fluid filters swiftly into the

wellbore and displaces the original fluids so that

the pore pressure, temperature and water content increase in the sediment around the borehole. At

the same time, the hydrates in the sediment are

heated to decompose into water and gas. As time goes on, the infiltration amount increases, the

temperature and pressure gradually transmit

around. At the beginning stage, there is a big pressure difference between borehole and the

sediment, but later the pressure line become

smooth with the pressure diffusion. Near the borehole(within 1m, shown in Figure 3), the

increasing water and gas content by hydrate

dissociation cause higher pressure than that without hydrate dissociation[71], i.e., the drop in pressure

become smooth, the increase degree of pore

pressure caused by drilling fluid invasion coupled with hydrate dissociation is larger than that in the

conventional oil and gas sediments. While away

from the borehole (beyond 1m), since there is no hydrate dissociation, the diffusion rule of pore

pressure is similar to the invasion of drilling fluid

into the conventional sediment. Besides, the hydrate dissociation is an endothermic reaction,

which causes the sharp drop of sediment

temperature near the borehole. Furthermore, the drilling fluid invasion can increase the pore. The

two factors make water and gas forming hydrates

again in the sediment. The re-formed hydrates are also called secondary hydrates. Because the

hydrate formation process is an exothermic

reaction, the temperature line become smooth within the radial distance of 0.75m-2.25m (shown

in Figure 4).

As time goes on, the hydrate dissociation degree increases gradually and the dissociation front

moves gradually into the deep sediment(shown in

Figure 5-7). In the beginning, the gas from hydrate

dissociation dissolves in the pore water. With the hydrate dissociation increases, the free gas

increases gradually and then some of them form

gas hydrates again somewhere in the sediment. At the same time, the hydrate dissociation will also

dilute the salinity of pore water, sequentially the

drop of the water mineralization in the sediment will take place. (shown in Figure 8).

Figure 3. The pore pressure of sediment around borehole as a function of time during the invasion

Figure 4. The temperature of sediment around

borehole as a function of time during the invasion

0.5 1.0 1.5 2.0 2.5 3.0

7

8

9

10

11

12

13

14

15

16

Tem

pe

ratu

re(°

C)

1min

10min

2h

5h

12h

17h

20h

24h

r(m))

hydrate dissociation

hydrate reformation

0.5 1.0 1.5 2.0 2.5 3.0

10.0

10.5

11.0

11.5

12.0

Pre

ssure

(MP

a)

r(m)

1min

10min

2h

5h

12h

17h

20h

24h

hydrate dissociation

0.0 0.5 1.0 1.5 2.0 2.5 3.0

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1min

10min

2h

5h

12h

17h

20h

24h

S_

aq

ue

ou

s

r(m)

Figure 5-6. The hydrate and aqueous saturation around borehole as a function of time during the invasion

0.0 0.5 1.0 1.5 2.0 2.5 3.0

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

1min

10min

2h

5h

12h

17h

20h

24hS_

ga

s

r(m) Figure 7-8. The free gas saturation and NaCl concentration around borehole as a function of time

The effect of drilling fluid density on the

invasion behaviors

Under the same temperature and drilling fluid's

salinity, the borehole pressure (i.e., density of drilling fluid) is changed in the simulations. It can

be found that the higher the pressure, the deeper

the invasion, and the speed and depth of heat transfer increases, and the larger degree of hydrate

dissociation (shown in fig.9-14). And the higher

pressure will quicken the pressure diffusion so that the influence of pores pressure increase induced by

the hydrate can be partly reduced (shown in Figure

10). Besides, to some extent the higher pressure will also inhibit the hydrates dissociation and result

in the smaller drop of sediment temperature while

the higher increase of sediment temperature when secondary hydrates form (shown in Figure 10).

Even the higher pressure can cause the whole gas

from hydrate dissociation to be dissolved into the pore water (shown in Figure 13). There would

form a relatively higher resistivity girdle band

induced by the water dilution and free gas from

hydrate dissociation in the sediment around the borehole comparing with the original sediment.

The longer the invasion time and the higher the

density, the deeper the girdle band(shown in Figure 14) .

The effect of drilling fluid temperature on the

invasion behaviors Under the same density and salinity of drilling

fluid, when its temperature is higher than that of

the hydrate stability, the higher its temperature, the larger degree of hydrate dissociation (shown in

Figure 15) and the farther the influenced

depth(shown in Figure16-19) . The displacement or push by the invasion will cause gas and water to

gather somewhere in the sediment and the pore

pressure to increase. In addition, such factors as the rapid drop of sediment temperature by hydrate

dissociation and the lag of heat transfer will

together cause the gas to form hydrates again even whose saturation is higher than that of the original

hydrates and then form a "highly saturated hydrate

0.5 1.0 1.5 2.0 2.5 3.0

3.37

3.38

3.39

3.40

3.41

3.42

3.43

3.44

3.45

3.46

3.47

3.48

3.49

3.50

3.51

1min

10min

2h

5h

12h

17h

20h

24h

Na

Cl(

%)

r(m)

dissociation dilution

0.5 1.0 1.5 2.0 2.5 3.0

0.0

0.1

0.2

0.3

0.4

0.5

1min

10min

2h

5h

12h

17h

20h

24h

S_

Hyd

rate

r(m)

hydrate dissociation

ring” around the borehole. It can be speculated that

the higher the temperature difference between the

drilling fluid and the sediment. the more obviously

this character is.

0 4 8 12 16 20

3600

3800

4000

4200

4400

4600

12MPa

15MPa

Re

ma

inH

yd

r(kg

)

Time(h) Figure 9. The hydrate left as a function of time Figure 10 The pore pressure as a function of distance (t=2h)

0.5 1.0 1.5 2.0 2.5 3.0

0.0

0.1

0.2

0.3

0.4

0.5

12MPa

15MPa

Sh

r(m) Figure 11. The temperature as a function of distance Figure 12 The distribution of hydrate saturation (t=2h)

Figure 13. The distribution of free gas saturation Figure 14 The distribution of NaCl concentration (t=2h)

The effect of drilling fluid salinity on the

invasion behaviors

Under the same conditions, the higher the drilling

fluid's salinity, the greater the hydrate dissociation by the invasion (shown in Figure 20), which can be

explained by two reasons: one is that the salt as

thermodynamic inhibitor can cause phase

equilibrium shift which benefits the dissociation, the other is that the increasing salinity will also

benefit the heat transfer because of the higher heat

conductivity of salts. The invasion of the drilling fluid with high concentration salt will also bring a

"highly saturated hydrate ring " around the

borehole, which is similar to that by the

0.5 1.0 1.5 2.0 2.5 3.0

9.5

10.0

10.5

11.0

11.5

12.0

12.5

13.0

13.5

14.0

14.5

15.0

15.5

12MPa

15MPa

Pre

ssu

re(M

Pa

)

r(m)

hydrate dissociation effect

0.5 1.0 1.5 2.0 2.5 3.0

3.40

3.42

3.44

3.46

3.48

3.50

12MPa

15MPa

Na

Cl(

%)

r(m)

forming relatively high-resistivity band

0.5 1.0 1.5 2.0 2.5 3.0

0.00

0.01

0.02

0.03

0.04

0.05

12MPa

15MPaSg

r(m)

0.5 1.0 1.5 2.0 2.5 3.0

7

8

9

10

11

12

13

14

15

16

12MPa

15MPa

Te

mp

era

ture

(C

)

r(m)

temperature(shown in Figure 21-24). Because of

the formation of secondary hydrate, the pressure

diffusion is retarded and the invasion process is

obstructed(Figure 25).

0 5 10 15

0

5

10

15

20

25

30

35

40

Cu

m_

CH

4_

Vo

l(m

3)

Time(h)

15C

20C

Figure 15. The accumulative gas from hydrate dissociation under different temperature of drilling fluid

0.5 1.0 1.5 2.0 2.5 3.0

0.4

0.5

0.6

0.7

0.8

0.9

1.0

15C

20C

Sw

r(m) Figure 16 The distribution of hydrate saturation Figure 17 The distribution of water saturation (t=2h)

0.5 1.0 1.5 2.0 2.5 3.0

0.00

0.01

0.02

0.03

0.04

0.05

0.06

15C

20C

Sg

r(m)

0.5 1.0 1.5 2.0 2.5 3.0

3.28

3.30

3.32

3.34

3.36

3.38

3.40

3.42

3.44

3.46

3.48

3.50

3.52

15C

20C

Na

Cl(

wt%

)

r(m) Figure 18 The distribution of free gas saturation Figure 19 The distribution of NaCl concentration (t=2h)

Discussions

Obviously, the hydrate stability around borehole depend on the density, temperature and salinity of

the drilling fluid during the course of invasion.

While the main factors which affect the drilling fluid invasion is the positive pressure difference

between the borehole and sediment, the

penetrability and the invasion time. Therefore, such an interesting question appears that what the

location relation is between the front of the drilling

fluid' invasion and that of the hydrate dissociation (shown in Figure 26). in other words, what 'is the

main factor deciding their location when the

invasion front edge exceeds the decomposition front edge or when the latter exceeds the former?

According to our simulations, we speculate that

when there is hydrate dissociation around the borehole, if there is small pressure difference, large

0.5 1.0 1.5 2.0 2.5 3.0

0.0

0.1

0.2

0.3

0.4

0.5

SH

r(m)

15C

20C

higher than original hydrate saturation

temperature difference and low sediment

penetrability, the invasion front lags the hydrate

dissociation front. If the condition is converse ,the invasion front exceeds the hydrate dissociation

front. But if there have big pressure difference,

great temperature difference and big sediment

penetrability, the situation is complicated because

the secondary hydrate will disturb the invasion

process. In general conditions, the hydrate dissociation front lags the invasion front of drilling

fluid.

0 2 4 6 8 10 12 14 16

-10

0

10

20

30

40

50

60

70

3.5% NaCl

10% NaCl

20% NaCl

Cu

m_

CH

4_

Vo

l(m

3)

Time(h)

Figure 20 The accumulative gas from hydrate dissociation Figure 21. The pore pressure distribution (t=2h)

Figure 22. The distribution of hydrate saturation Figure 23. The distribution of water saturation (t=2h)）

0.5 1.0 1.5 2.0 2.5 3.0

-0.01

0.00

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

3.5 wt% NaCl

10 wt% NaCl

20 wt% NaClSg

r(m)

0.5 1.0 1.5 2.0 2.5 3.0

10.0

10.5

11.0

11.5

12.0

3.5 wt% NaCl

10 wt% NaCl

20 wt% NaCl

Pre

ssu

re(M

Pa

)

r(m) Figure 24 The distribution of free gas saturation Figure 25 The distribution of pore pressure

0.5 1.0 1.5 2.0 2.5 3.0

0.4

0.5

0.6

0.7

0.8

0.9

1.0

3.5 wt% NaCl

10 wt% NaCl

20 wt% NaCl

Sw

r(m)

hydrate

reformation

0.5 1.0 1.5 2.0 2.5 3.0

3

4

5

6

7

8

9

10

11

12

13

14

15

16

3.5 wt% NaCl

10 wt% NaCl

20 wt% NaCl

Te

mp

era

ture

(C

)

r(m)

heat liberation by reformation

heat absorption by dissociation

0.5 1.0 1.5 2.0 2.5 3.0

0.0

0.1

0.2

0.3

0.4

0.5

0.6

3.5 wt% NaCl

10 wt% NaCl

20 wt% NaCl

Sh

r(m)

higher hydrate saturation

Figure 26. The position relationship between the

front of the drilling fluid' invasion and that of the

hydrate dissociation In addition, the gas hydrate is similar to ice which

is dielectric. Therefore, the sediment appears high

apparent resistivity on the dynamic responding characters[54-59]. But in the drilling of marine

hydrates, normally high-containing salts such as

NaCl and KCl are added into the drilling fluid in order to inhibit the hydrate formation in the BOP

and keep the wellbore stability. Therefore, there is

a higher mineralization of the drilling fluid. When it invades, the dynamic responding characters of

resistivity well logging appear a resistivity drop

with the increasing water content by the hydrate dissociation. But the water will dilute the pore

water to some degree and the gas from the hydrate

dissociation will increase the resistivity, so the dynamic responding characters of the resistivity

well logging accompanied by drilling fluid

invasion and hydrate dissociation are more complicated than that of the conventional

sediment. The above mentioned problems need to

be investigated by further simulations and extra experiments.

CONCLUSIONS AND SUGGESTIONS

The dynamic characteristics of water-based drilling fluid invading into hydrate-bearing sediment were

investigated by employing the TOUGH+

HYDRATE code developed by LBNL. The preliminary results are shown as follows according

to the simulations.

(1) Under the overbalanced drilling condition, the invasion of drilling fluid into hydrate-bearing

sediment is coupled with hydrate dissociation and

reformation if the temperature of drilling fluid containing salts is higher than the equilibrium

temperature of gas hydrate under the same salt

concentration condition. They interact on each other and together determine the degree of drilling

fluid invasion and hydrate dissociation, which

further influences the mechanical properties, pore

pressure, water/gas/hydrate saturation,

permeability, resistivity and wave velocity of the

sediment around borehole. Both the invasion of drilling fluid and hydrate dissociation will increase

the pore pressure and water content and

correspondingly decrease the effective stress and intergranular cohesion of sediment, which would

cause wellbore instability.

(2) When the density and salinity of drilling fluid keep constant, the higher the temperature of

drilling fluid, the larger degree of hydrate

dissociation. At the same time, the gas and water produced from hydrate dissociation can re-form

again at the certain depth in the radial sediments

due to the pore pressure increase caused by drilling fluid invasion, the heat adsorption of hydrate

dissociation and the heat diffusion delay of

sediment, etc. Even the hydrate saturation in this place is higher than that in situ sediment and thus it

forms a high-saturation hydrate girdle band around

the borehole. The reason for this is that the gas from hydrate dissociation is squeezed by the

displacement of the drilling fluid invasion and

cumulates to a larger concentration at the certain depth in the sediment.

(3)When the salinity of drilling fluid is same with

that of the pore water in the sediment near the borehole, the larger the density of drilling fluid, the

deeper invasion and heat transfer, and the more

hydrate dissociation. There would form a relatively higher resistivity girdle band induced by

the water dilution and free gas from hydrate

dissociation in the sediment around the borehole comparing with the original sediment.

(4) When the density and temperature of drilling

fluid keep constant, the higher salinity of drilling fluid, the larger degree of hydrate dissociation due

to the stronger thermodynamic inhibition effect and

heat transfer efficiency during the invasion process. The high salt concentration of drilling

fluid invasion would cause the similar high-

saturation hydrate girdle band around borehole like the high temperature of drilling fluid. The final

salinity distribution around borehole depends on

the salinity of drilling fluids and the degree of hydrate dissociation and reformation.

(5) Under the simulation conditions, it is found that the appearance of high-saturation hydrate girdle

band mainly depends on the temperature and

salinity of drilling fluids. Therefore, when drilling in the hydrate-bearing

sediment, managed pressure drilling operation

should be employed to keep the suitable downhole

pressure difference and ensure wellbore

stabilization, well drilling safety and well logging

accuracy. Our simulation results also show that even the LWD method might not be accurate in the

hydrate-bearing sediment if the invasion condition

is out of hydrate stability zone because the drilling fluid invasion and hydrate dissociation are very

quick. The best way to avoid this is to adopt the

deep laterolog method. In addition, it is better to select low salinity drilling fluid system for drilling,

i.e., reducing the addition of salts which would

influence the resistivity logging and hydrate stability around borehole. At the same time, the

drilling fluid should be kept cool and fast

circulation. However, the low temperature of drilling fluid circulation would cause the gas

spilled from hydrate dissociation near the borehole

re-form and aggregate in the borehole. So it is best to add the kinetic inhibitors or kinetic inhibitors

(KHIs) or anti-agglomerants (AAs) into drilling

fluids rather than salts that are thermodynamic inhibitors. In the future work, we will investigate

the influence of drilling fluid invasion on the

geophysical properties of hydrates bearing sediment and the resistivity logging by integrating

with the practical drilling operations and

experimental tests.

ACKNOWLEDGEMENTS

The authors would like to thank Dr. George

Moridis for valuable suggestions on our models and theoretical analysis.

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