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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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