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Energies 2011, 4, 140-150; doi:10.3390/en4010140
energies
ISSN 1996-1073
www.mdpi.com/journal/energies
Article
Polyethylene Glycol Drilling Fluid for Drilling in Marine Gas
Hydrates-Bearing Sediments: An Experimental Study
Guosheng Jiang *, Tianle Liu, Fulong Ning *, Yunzhong Tu, Ling Zhang, Yibing Yu and
Lixin Kuang
Faculty of Engineering, China University of Geosciences, Wuhan, 430074, China;
E-Mails: liutianle2008@163.com (T.L.); tumichael@163.com (Y.T.); flyzling@yahoo.com.cn (L.Z.);
chu05@163.com (Y.Y.); kuanglx@joeco.com.cn (L.K.)
* Authors to whom correspondence should be addressed; E-Mail: jianggs65@vip.sina.com (G.J.);
nflzx@cug.edu.cn (F.N.); Tel./Fax: +86-27-67883507.
Received: 10 December 2010; in revised form: 23 December 2010 / Accepted: 14 January 2011 /
Published: 19 January 2011
Abstract: Shale inhibition, low-temperature performance, the ability to prevent calcium
and magnesium-ion pollution, and hydrate inhibition of polyethylene glycol drilling fluid
were each tested with conventional drilling-fluid test equipment and an experimental
gas-hydrate integrated simulation system developed by our laboratory. The results of these
tests show that drilling fluid with a formulation of artificial seawater, 3% bentonite,
0.3% Na2CO3, 10% polyethylene glycol, 20% NaCl, 4% SMP-2, 1% LV-PAC, 0.5% NaOH
and 1% PVP K-90 performs well in shale swelling and gas hydrate inhibition. It also shows
satisfactory rheological properties and lubrication at temperature ranges from −8 °C to
15 °C. The PVP K-90, a kinetic hydrate inhibitor, can effectively inhibit gas hydrate
aggregations at a dose of 1 wt%. This finding demonstrates that a drilling fluid with a high
addition of NaCl and a low addition of PVP K-90 is suitable for drilling in natural marine
gas-hydrate-bearing sediments.
Keywords: marine gas hydrate; drilling fluid; polyethylene glycol; kinetic inhibitor
OPEN ACCESS
Energies 2011, 4
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1. Introduction
Gas hydrates are clathrate non-stoichiometric compounds, in which the molecules of gas are
encaged in crystalline cells, consisting of water molecules retained by the energy of hydrogen
bonds [1]. They are also called clathrate hydrates or “flammable ice” [2]. Natural-gas hydrates are
distributed widely in marine continental margin sediments and permafrost environments, with the
overwhelming majority of hydrate reservoirs discovered existing in the former location [3]. It is
believed that the energy in these hydrate deposits is likely to be significant compared to other types of
fossil fuel deposits [4,5]. Since natural gas hydrates have the attributes of high energy density, large
reserves, and relative cleanliness [6], they are currently considered a potential unconventional
energy resource [7,8].
During the process of exploring and exploiting this energy resource, drilling is the most direct and
important approach. When drilling in oceanic gas-hydrate-bearing sediments, the disturbance of in situ
formations by drilling can alter the conditions and make gas hydrates unstable. The dissociation of gas
hydrate can lead to a series of problems related to drilling safety. In the case of an uncased borehole,
the gas-hydrate dissociation will cause the borehole to become unstable, and the gas released by
gas-hydrate dissociation will erode the drilling pipe and leak at the seafloor [9–13]. The gas circulated
with drilling fluids may also re-form as a hydrate, blocking the drilling pipe terminating the fluid
circulation [14–16]. In addition, the abundance of gas may result in blowouts at the surface or
gasifying the seawater, which would cause the platform to lose buoyancy and possibly collapse. If the
borehole is cased, the high pressure accompanied by gas-hydrate dissociation may cause casing failure
and borehole collapse. In recent decades, the petroleum industry has expanded drilling operations into
deep-water areas, and the pace of gas-hydrate exploitation has accelerated. Because of this, the
problems related to conventional oil or gas drilling in deep water or marine hydrate reservoirs must be
taken into consideration. Barker et al. [14] first reported two drilling accidents involving gas hydrate
formation in drilling fluids, one at Santa Barbara, California, and the other at Green Canyon in the
Gulf of Mexico. Birchwood et al. [17] concluded that by cooling drilling fluid and decreasing the
circulation rate, the influence of drilling through gas-hydrate-bearing sediments on petroleum
operations can be minimized. Therefore, it is important to take appropriate efforts to minimize
gas-hydrate dissociation or inhibit the formation of gas hydrate within the drill string or annulus to
ensure safe drilling operations. This matter depends on the rational drilling fluids system. The choice
of drilling fluids plays an important role in achieving the above-mentioned objectives.
In order to overcome the problems that might be encountered during drilling in oceanic
gas-hydrate-bearing sediments, a suitable drilling-fluid system should have the following characteristics:
(1) The relative density (
ρ
) of the drilling fluid must have an appropriate changing range. The
drilling fluid can supply a definite pressure to counteract the stratums and prevent hydrates
around the borehole from decomposing to keep the borehole wall stable. For a practical
situation of hydrates sediment, results of previous experiments in our lab indicate the optimum
relative density is in the range of 1.05–1.2 [18], according to the safe density window of
drilling fluid.
(2) The drilling fluid should be able to effectively inhibit shale hydration and gas-hydrate
aggregations in the drilling pipe and blowout preventer.
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142
(3) The drilling fluid should have a low temperature that can effectively prevent the dissociation of
hydrates around the borehole.
(4) The drilling fluid should have good rheological properties and stability at low temperatures.
(5) The drilling fluid should prevent calcium- and magnesium-ion pollution. Normally, the
concentration of calcium and magnesium ions in the ocean is about 0.40 g/kg and 1.28 g/kg,
respectively [19]. Though these percentages are very small, they can greatly influence the
performance of the drilling fluid.
(6) The drilling fluid must have sufficient lubrication and low filtration.
At present, the typical drilling-fluid system used in offshore drilling is a polymer drilling fluid
containing salts and organic agents, which are well-known thermodynamic hydrate inhibitors. Water-based
polymer drilling fluids with a high salt content and partially hydrolyzed polyacrylamide (PHPA) have
been successfully used in many deep-water drilling activities [20,21]. In most cases, the
thermodynamic inhibitors are added into drilling fluids to prevent gas-hydrate formation in deep water
drilling, whereas the results of kinetic hydrate inhibitors (KHIs) are still under investigation [22–24].
Compared with traditional thermodynamic inhibitors, kinetic inhibitors are effective at very low
addition (generally 0.01–1 wt%), which can significantly reduce the drilling cost. At the same time,
kinetic inhibitors are more environmentally friendly and could be applied under more and more
restrictive regulations [25]. In addition, for deep-water drilling in gas-hydrate-bearing sediments, the
use of thermodynamic inhibitors for hydrate inhibition should be considered carefully because they
prevent hydrate aggregations in the borehole, but can also cause the dissociation of hydrates occurring
around the borehole sediment if their concentration is too high [26], which can then affect borehole
stability. Because of this, KHIs or anti-agglomerants (AAs) should also be considered for preventing
hydrate aggregations that may form during marine gas-hydrate drilling. In this work, we develop a
formulation of polyethylene-glycol drilling fluid with added KHI specially designed for drilling in
gas-hydrate-bearing sediments. We simulate the conditions encountered in deep-water drilling and
evaluate the performance of the drilling fluid. The shale inhibition, low-temperature performance,
ability to prevent calcium- and magnesium-ion pollution, and hydrate inhibition of the polyethylene
glycol drilling fluid were each tested by employing conventional drilling-fluid test equipment and a
gas-hydrates integrated-simulation experimental system developed by our laboratory.
2. Experimental
2.1. Apparatus
The conventional performance test equipment used for testing the drilling fluid includes a mud
densimeter, a ZNN-D6 rotational viscosimeter, an HAPI filter press and a ZNP swelling amount tester.
The experimental gas-hydrate integrated simulation system was used to test the inhibition of hydrate
formation in drilling fluid. This system has also been used in our previous work [27]. It was developed
to run various hydrate and drilling-fluid simulation tests. A schematic of the experimental apparatus is
shown in Figure 1.
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143
Figure 1. Schematic diagram of the experimental gas-hydrate integrated simulation system.
Shutoff valve
Vacuum
pump
Prog rammable
Cooler
Data
acquisition
T3
Air
bath
Autoclave
T2
T1 p
Hi gh -pressure
switching desk
Compressor
Booster pump unit
Press ure
gauge
Shutoff valve
Gas
cyl in der
Recovery
cylinder
2.2. Materials
The polyethylene glycol used in the experiments was produced by Shanghai Shiyi Chemical
Reagent Co. Ltd. Its average relative molecular weight is 2000 ± 10. The kinetic inhibitor polyethylene
pyrrolidone PVP K-90 was made by Henan BoAi Pharmaceuticals Co. Ltd. The methane was provided
by Wuhan Huaxing Industrial Technology Co. Ltd., with a purity of 99.9%. The other reagents used in
this drilling fluid were commonly used products produced by well-known companies.
2.3. Principles and Procedure
Due to the fact that seawater has been used as the drilling fluid for most offshore drillings, we used
it to make the drilling fluid. For our experiment, man-made seawater was employed. The salinity of
our man-made seawater was about 3.4%, which is common for natural seawater worldwide. According
to the laboratory research and practical drilling operations, drilling fluid containing 10% polyethylene
glycol and 20% NaCl has a relatively comprehensive performance [28,29], so the designed formula for
our polyethylene-glycol drilling fluid for marine gas-hydrates drilling is artificial seawater, 3% sodium
bentonite, 1% LV-PAC, 4% SMP-2, 10% polyethylene glycol, 20% NaCl, 1% PVP K-90 and
0.5% NaOH. The formula and the concrete concentration of each component were designed based on
our and other researchers’ previous work [30–32]. All the percentages are expressed in mass ratios. In
this formula, low-viscosity polyanionic cellulose (LV-PAC) and sulfomethylated phenolic resin
(SMP-2) can reduce the filtration of drilling fluid, and PVP K-90 is a kinetic hydrate inhibitor. Since
1990s, many types of KHIs have been developed [25]. The PVP was considered the first generation of
KHIs. Although the subsequent KHIs such as PVCap and Gaffix VC-713 outperform PVP, the PVP is the
basic one and has relatively easier acquisition and lower cost compared with these KHIs. So it is
selected as the hydrate inhibitor in our study. In addition, the addition of NaOH can adjust the pH
value of the drilling fluid.
The normal performance of the polyethylene-glycol drilling fluid was tested using the conventional
equipment. The ZNP swelling amount tester was used to test the shale inhibition. The mud densimeter,
Energies 2011, 4
144
the ZNN-D6 rotational viscosimeter and the HAPI filter press were used to test the density, rheology
and filtration at low temperatures, respectively. In the low-temperature tests, the drilling fluid and the
test equipment were put into a programmable cooler according to the order of corresponding tests. The
programmable cooler was set at a predefined temperature to cool the drilling fluid. When the cooler
reached the predefined temperature, the drilling fluid was stirred every ten minutes for one hour,
allowing the drilling fluid to reach a uniform temperature. Then, the corresponding tests were
performed. Next, the hydrate inhibition of the drilling fluid was tested by the simulation experimental
system shown in Figure 1. About 2000 mL of drilling fluid and some methane were injected into an
autoclave until the pressure in the autoclave reached 18 MPa. The autoclave was kept in the programmable
cooler which was set at 4 °C for 20 hours. This temperature (4 °C) and pressure (18 MPa) simulate the
conditions in water at a depth of 1800 m. Because the formation of hydrate consumes gas and releases
heat, the pressure inside the autoclave would decrease and its temperature would increase during the
experiments. These changes could then be used to evaluate hydrate formation in the drilling fluid and
the effectiveness of the inhibitor used.
3. Results and Analysis
3.1. Shale Inhibition
There are two common methods for shale-inhibition evaluation: The dispersing inhibition test (rolling
collection test) and the expansion inhibition test. Here, the shale expansion tests were conducted and
compared with a pure-water system. The results are shown in Table 1.
Table 1. The results of the shale expansion experiments.
Test System Linear Expansivity (%)
2 h 4 h 6 h 8 h 10 h 12 h 14 h 16 h
Pure water 6.8 14.3 27.7 33.5 36.7 39.0 39.8 40.5
The drilling
fluid system 3.2 6.8 8.5 9.7 11.5 12.9 13.5 13.8
As can be seen in Table 1, the polyethylene-glycol drilling fluid has a significant inhibition on shale
expansion. After two hours, the linear expansivity of shale in drilling fluid was only 3.2%, a reduction
of 52.94% compared to that in pure water. After 16 h, the linear expansivity of shale in drilling fluid
was 13.8%, a reduction of 65.93% compared to that in pure water. Furthermore, as can be seen from
Figure 2, the linear expansivity of shale in pure water had a significant growth trend throughout the
whole test, while the linear expansivity of shale in the polyethylene-glycol drilling fluid was changed
very slowly.
3.2. Properties at Low Temperature
The temperature of circulating drilling fluid is normally about 0 °C to 6 °C when drilling in deep
water. For our test, we expanded the possible range of circulating drilling fluid temperatures to range
from −8 °C to 15 °C. The density (
ρ
), rheology (plastic viscosity (PV), gel strength (Gel), and yield
point (YP)) and filtration (FL) of the drilling fluid were each tested.
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145
Figure 2. The shale expansion in the pure water and the drilling fluid.
Table 2. The rheological properties of polyethylene-glycol drilling fluid at different temperatures.
T (°C)
ρ
(g/cm3) Gel (Pa/Pa) PV (mPa·s) YP (Pa) FL (mL)
15 1.15 2/2.5 18 8.5 5.5
8 1.15 2/2.5 20 8.9 5.5
0 1.16 2.5/3 21 9.2 5.5
−4 1.16 2.5/3 22 9.7 5.7
−8 1.16 2.5/3 25 10.2 5.8
Figure 3. The change of gel strength and yield point of polyethylene glycol drilling fluid at
different temperatures.
These results are shown in Table 2. As can be seen from Table 2 and Figure 3, the PV and Gel value
had increasing trends, but the changes were small and acceptable. Furthermore, the high ratios of yield
point and plastic viscosity would help to carry cuttings and clean the borehole. Although filtration had
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146
an increasing trend, it showed very little change. In conclusion, the polyethylene glycol exhibited good
performance as measured by rheological properties and stability at low temperature.
3.3. Prevention of the Pollution Caused by Calcium and Magnesium Ions
During the drilling operation process, sediment water and seawater containing calcium and
magnesium ions can enter into the borehole and mix with drilling fluids, which pollutes the drilling
fluids and changes their performance. To test the ability of the drilling fluid to prevent pollution from
calcium and magnesium ions, experiments were performed by adding different amounts of MgCl2
and CaCl2 into the polyethylene-glycol drilling fluid in the laboratory. The test results are shown in
Table 3. The shear viscosity of drilling fluid increased with increased amounts of MgCl2 and CaCl2,
but the change was very small, as was the filtration. In other words, the polyethylene-glycol drilling
fluid has an excellent anti-pollution ability against calcium and magnesium ions.
Table 3. Experiment for preventing pollution by calcium and magnesium ions.
Formula PV (mPa.s) YP (Pa) Gel (Pa/Pa) FL (mL)
The drilling fluid 18.0 8.5 2/2.5 5.5
The drilling fluid + 0.3% MgCl2
+ 0.1% CaCl2 18.5 9.2 2.5/3 5.5
The drilling fluid + 0.51% MgCl2
+ 0.18% CaCl2 20.0 9.0 3/3.5 5.8
The drilling fluid + 0.8% MgCl2
+ 0.4% CaCl2 21.5 9.0 3/3.5 5.8
3.4. Hydrate Inhibition
To test hydrate inhibition, the drilling fluid without PVP K-90 was injected into the autoclave and
cooled to 4 °C by the programmable cooler under 18 MPa pressure. The whole cooling time was 20 h.
During the experiment, the pressure and the temperature in the autoclave changed significantly
(Figure 4a). The pressure decrease significantly from 18 MPa at the beginning to 13.5 MPa at the end.
At the beginning of experiment, the pressure reduced slowly because some methane gas was dissolving
in the drilling fluid. The temperature had a sharp rise when the experiment lasted for 900 min, which
could indicate that there were a large number of hydrates formed. This also implies that only relying
on the thermodynamic inhibitors (in this case, the drilling fluid contains 20% NaCl) can not fully
prevent hydrate formation and aggregation under this temperature and pressure. Under the same
conditions, drilling fluid with 1 wt% PVP K-90 was injected into the autoclave. The results showed no
significant change in temperature and pressure in the autoclave over 20 hours (Figure 4b). The
pressure was 18 MPa at the beginning and 17.5 MPa at the end, and the lost 0.5 MPa was likely due to
the methane dissolution in the drilling fluid (the solubility of methane at 18 MPa, 4 °C in the
20% NaCl solution is about 34.32 mM [33], the corresponding dissolution gas volume in the drilling
fluid is about 1.5 L at standard condition). Furthermore, the temperature in the autoclave showed
almost no change. This indicates that no hydrates formed in the autoclave. This experiment shows that
a low dose of PVP K-90 has excellent performance on hydrate-formation inhibition, and the
polyethylene-glycol drilling fluid is able to effectively inhibit gas-hydrate formation at low
Energies 2011, 4
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temperature and high pressure. The inhibition would be even more obvious with the addition of more
PVP K-90. However, since it is a macromolecule polymer, adding too much PVP K-90 would
inevitably lead to excessive shear viscosity. Table 4 shows the effect of PVP K-90 on the rheological
properties of polyethylene-glycol drilling fluid. It can be found that the gel strength and yield point of
drilling fluid are preferable when the concentration of PVP K-90 increases to 1%, especially the plastic
viscosity that reaches 20 mPa·s.
Figure 4. The contrast of temperature and pressure evolution of polyethylene glycol
drilling fluid with and without the addition of PVP K-90 (a) in absence of PVP and (b) in
presence of PVP.
(a) (b)
Table 4. The rheological properties of polyethylene-glycol drilling fluid with different
PVP K-90 concentration.
PVP Content
ρ
(g/cm3) Gel (Pa/Pa) PV (mPa.s) YP (Pa) FL (mL)
0.4% 1.165 1.5/2.0 12.0 5.1 11.0
0.5% 1.165 1.5/2.0 13.0 5.1 10.8
0.6% 1.165 1.0/2.0 14.5 6.6 10.4
0.7% 1.166 1.5/2.5 16.8 3.6 9.5
0.8% 1.166 1.5/2.0 18.0 4.6 7.8
0.9% 1.167 2.0/2.5 18.5 8.7 6.5
1.0% 1.168 2.0/2.5 20.0 9.2 5.5
1.1% 1.168 2.0/3.0 22.5 8.7 5.5
1.2% 1.168 2.5/4.5 23.0 9.7 5.5
Besides, the yield point/plastic viscosity ratio approaches 0.46, which also shows that the drilling
fluid has good rheological properties and can effectively lubricate drilling tools, suspend drilling
cuttings and stabilize boreholes. If the concentration of PVP K-90 increases more than 1%, the
rheological properties of drill fluid become worse, which will influence the circulation rate of drilling
fluid and even cause pressure surges in the borehole. Therefore, the concentration of 1% PVP K-90
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can achieve the balance of good hydrate inhibition and relatively suitable rheology behavior in the
polyethylene-glycol drilling fluid over at least 20 h at 18 MPa pressure and low temperature.
4. Conclusions and Suggestions
(1) The designed polyethylene-glycol drilling-fluid system has good performance concerning shale
and gas-hydrate inhibition, rheological properties and stability at low temperature. Its density is also
appropriate for this application. This drilling fluid can effectively prevent pollution caused by calcium
and magnesium ions. Therefore, it is able to maintain borehole stability, suspend drilling cuttings, and
clean the bottom of the borehole while drilling.
(2) If sea depth exceeds a certain value, only relying on the thermodynamic inhibitors (in this case,
the drilling fluid contains 20% NaCl and 10% polyethylene glycol) can’t fully prevent hydrate
formation in the designed drilling fluid. Adding a small amount of the kinetic inhibitor PVP K-90 into
the polyethylene-glycol drilling fluid can effectively inhibit hydrate nucleation and aggregation; it can
also prevent the gas dissociated from hydrates around the borehole from re-forming as hydrates later in
the cycle pipeline.
(3) While drilling in gas-hydrate-bearing formations, it is suggested that the drilling fluid have a
high circulating speed to inhibit gas-hydrate decomposition and reformation. Because the heat
produced by aiguilles cutting stratums can be rapidly dissipated by the drilling fluid, the drilling fluid
can be renovated rapidly. This process is helpful for cooling the drilling fluid by the cold water around
drill pipes in deep seas, which can help control dissociation of the hydrates around the borehole and
wellbore stability.
Acknowledgements
The paper is sponsored by Project 863 (No.2006AA09Z316), National Natural Science Foundation
of China (No. 40974071, 50704028, 50904053), Program for New Century Excellent Talents in
University (No. NCET-05-0663), and Graduate Academic Research and Innovation Foundation of
CUG (No. CUGYJS0803). This work was also partially supported by the Fundamental Research Funds
for the Central Universities (No. CUGL100410).
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