UNIVERSITY OF CALGARY
Design of Low-toxic Non-solid Anti-freeze Polymer Drilling Fluid
by
Hai Wang
A THESIS
SUBMITTED TO THE FACULTY OF GRADUATE STUDIES
IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE
DEGREE OF MASTER OF SCIENCE
GRADUATE PROGRAM IN CHEMICAL AND PETROLEUM ENGINEERING
CALGARY, ALBERTA
AUGUST, 2014
© Hai Wang 2014
ABSTRACT
Drilling in permafrost and at low temperature are two challenges that complicate Arctic
operation. Addressing these challenges require new approaches in drilling fluid design and
optimization. This experimental study proposes formulations for low-toxic anti-freeze agents and
non-solid polymer system. Tests are conducted to verify that 5% NaCl + 5% KCl + 30% glycerol
are effective to maintain the freezing point below -20°C. Experiments were performed on the
influence of anti-freeze agent on the rheological and filtration control of polymer solutions.
Three formulated polymer systems are demonstrated to be able to generate desirable viscosity
and yield point to provide efficient hole cleaning at temperature range of -20°C ~ 0°C. The
desirable filtration characteristics are shown by generating the minimized volume of filtrate. A
rheological model describing the flow behavior of anti-freeze polymer fluids is selected and used
to predict the frictional pressure loss in a simulated mud circulation.
ii
ACKNOWLEDGEMENT
I would like to express my sincere gratitude to Dr. Robert Martinuzzi, for his continuous
support and patience throughout this work. I will never forget his words of wisdom for years to
come. I would also like to thank Dr. Victoria Kostenko. Her contribution in guiding me and
constantly being available to discuss my problems cannot be overemphasized in the success of
this work.
Special thanks to Dr. Geir Hareland, for accepting me into the research group and sponsoring
my project. To Marquis Alliance and its research chemists Stuart Dubberley and Eric Sonmor,
my thanks for provision of materials for my studies.
I would also like to thank Dr. Budiman, Dr. Gates and Dr. Mehta, for taking out time to be on
my graduate committee.
I would especially like to thanks to the faculty and staff of the Schulich School of
Engineering for their prompt attention to my questions and needs.
Finally, my huge thanks to all my colleagues in the Real-time Drilling Engineering Research
Group at University of Calgary for their support and help in every way.
Thank you all for giving me this wonderful experience.
iii
TABLE OF CONTENTS
ABSTRACT .................................................................................................................................... ii
ACKNOWLEDGEMENT ............................................................................................................. iii
TABLE OF CONTENTS ............................................................................................................... iv
LIST OF FIGURES ...................................................................................................................... vii
LIST OF TABLES ......................................................................................................................... ix
LIST OF SYMBOLS, ABBREVIATIONS, NOMENCLATURES ............................................. xi
CHAPTER 1: INTRODUCTION ................................................................................................... 1
1.1
Arctic oil and gas production potential .......................................................................... 1
1.2
Challenges in Arctic drilling .......................................................................................... 2
1.2.1
Structure of permafrost ............................................................................................... 2
1.2.2
Temperature profile when drilling permafrost ........................................................... 3
1.3
Criteria for drilling fluids designed for Arctic drilling .................................................. 5
1.4
Objectives of study ........................................................................................................ 8
CHAPTER 2: LITERATURE REVIEW ........................................................................................ 9
2.1
The development of Arctic drilling ............................................................................... 9
2.2
The development of anti-freeze drilling fluid .............................................................. 11
2.2.1
Types of drilling fluids for arctic drilling ................................................................. 11
2.2.2
Antifreeze agents for drilling fluids.......................................................................... 13
2.2.3
Polymer for anti-freeze drilling fluids ...................................................................... 20
2.2.4
Candidates of drilling fluid component .................................................................... 25
CHAPTER 3: METHOD OF RESEARCH .................................................................................. 26
3.1
Overview.................................................................................................................... 26
3.2
Experimental procedure for freezing point and salt solubility of anti-freeze agents ... 26
3.3
Rheology test of anti-freeze polymer systems ............................................................. 27
3.3.1
Experiment for the rheology test of polymer systems at different concentrations ... 27
3.3.2
Rheology test of polymer in presence of anti-freeze agent ...................................... 30
3.4
Experiments of filtration of anti-freeze polymer systems ........................................... 31
CHAPTER 4: DESIGN OF ANTI-FREEZE BASE FOR ARCTIC DRILLING FLUID........... 33
4.1
Freezing and salt-out temperature for NaCl and glycerol ............................................ 33
iv
4.2
Freezing and salt-out temperature for KCl and glycerol ............................................. 35
4.3
Minimization of anti-freeze agent concentration ......................................................... 36
CHAPTER 5: RHEOLOGY OF ANTI-FREEZE POLYMER SYSTEM .................................... 40
5.1
Experiment for optimum concentration of polymer solutions ..................................... 40
5.1.1 Viscosity and yield point of xanthan gum solution as a function of concentration and
temperature ............................................................................................................................ 41
5.1.2 Viscosity and yield point of guar gum solution as a function of concentration and
temperature ............................................................................................................................ 43
5.1.3 Viscosity and yield point of modified starch solution as a function of concentration
and temperature ..................................................................................................................... 44
5.1.4 Viscosity and yield point of methylcellulose solution as a function of concentration
and temperature ..................................................................................................................... 45
5.1.5 Viscosity and yield point of MF PAC-LV as a function of concentration and
temperature ............................................................................................................................ 48
5.1.6 Analysis of rheology performance of polymer solutions at different concentrations
49
5.2
Rheology of polymers in response to anti-freeze base ................................................ 50
5.2.1 Viscosity and yield point of 0.2% xanthan gum solution as a function of salinity and
temperature ............................................................................................................................ 51
5.2.2 Viscosity and yield point of 0.3% guar gum solution as a function of salinity and
temperature ............................................................................................................................ 52
5.2.3 Viscosity and yield point of 1% modified starch solution as a function of salinity
and temperature ..................................................................................................................... 54
5.2.4 Viscosity and yield point of 0.5% MF PAC-LV solution as a function of salinity and
temperature ............................................................................................................................ 55
5.2.5 Viscosity and yield point of 0.6% MC M0387 solution as a function of salinity and
temperature ............................................................................................................................ 56
5.2.6
Analysis of the response of polymer solution to anti-freeze agent........................... 57
CHAPTER 6: RHEOLOGICAL MODELS AND HYDRAULICS ESTIMATION OF ANTIFREEZE POLYMER SYSTEMS ................................................................................................. 60
6.1
Rheological model optimization .................................................................................. 60
6.1.1
Newtonian Model ..................................................................................................... 62
6.1.2
Bingham Plastic Model ............................................................................................ 64
6.1.3
Power Law Model .................................................................................................... 65
v
6.1.4
API Model (RP 13D) ................................................................................................ 66
6.1.5
Herschel-Bulkley Model........................................................................................... 68
6.1.6
Conclusion of rheological model selection .............................................................. 69
6.2
Hydraulics estimation .................................................................................................. 70
6.2.1
Frictional Pressure Loss Calculation ........................................................................ 71
6.2.2
Hydraulics Simulation .............................................................................................. 73
CHAPTER 7: FILTRATION CONTROL OF ANTI-FREEZE POLYMER SYSTEMS ............ 76
7.1
Basic theory of filtration property ............................................................................... 76
7.2
Filtration test of polymer solutions .............................................................................. 77
7.3
Filtration of polymers in response to anti-freeze base ................................................. 79
7.4
Rheology test of anti-freeze polymer systems ............................................................. 80
7.5
Hydraulics Simulation ................................................................................................. 81
7.6
Cuttings carrying capacity ........................................................................................... 85
CHAPTER 8: SUMMARY, CONCLUSIONS AND RECOMMENDATIONS ......................... 87
8.1
Summary ...................................................................................................................... 87
8.2
Conclusions .................................................................................................................. 88
8.3
Recommendations for future research ......................................................................... 89
REFERENCES ............................................................................................................................. 90
APPENDIX A - DATA SPREADSHEETS ................................................................................. 97
APPENDIX B - MATERIAL SAFETY DATA SHEET ........................................................... 105
APPENDIX C- PRODUCT DATA SHEET .............................................................................. 112
vi
LIST OF FIGURES
Figure 1.1.Circumpolar belt of hydrocarbon accumulation ............................................................ 1
Figure 1.2.Three-dimensional diagram of permafrost, Kivalliq, Nunavut, Canada ....................... 2
Figure 1.3.Outside working time limitation on Kharyaga, Russia ................................................. 4
Figure 1.4.Average temperature profile of formation in a permafrost region ................................ 5
Figure 2.1.Effect of NaCl concentrations on maximum swelling rate of clay ............................. 17
Figure 2.2.Solubility curves at standard pressure ......................................................................... 18
Figure 3.1.Schematic diagram of the Fann Model 35 viscometer ................................................ 29
Figure 3.2.Fann Model 300 LPLT Filter Press ............................................................................. 31
Figure 4.1. Dissolved solution (left); ice crystal (middle) and salt-out (right) .................................. 34
Figure 5.1.Test results of plastic viscosities and yield points of xanthan gum solutions ............. 42
Figure 5.2.Test results of plastic viscosities and yield points of guar gum solutions ................... 43
Figure 5.3.Test results of plastic viscosities and yield points of modified starch solutions ......... 44
Figure 5.4.Plastic viscosities and yield points of M7140 methylcellulose solutions.................... 46
Figure 5.5.Plastic viscosity and yield point of M0262 methylcellulose solutions........................ 47
Figure 5.6.Plastic viscosities and yield point of M0387 methylcellulose solutions ..................... 48
Figure 5.7.Plastic viscosity and yield point of MF PAC LV solutions ........................................ 49
Figure 5.8. Plastic viscosity and yield point of anti-freeze xanthan solutions.............................. 52
Figure 5.9.Plastic viscosity and yield point of anti-freeze guar gum solutions ............................ 53
Figure 5.10.Plastic viscosity and yield point of anti-freeze modified starch solutions ................ 55
Figure 5.11.Plastic viscosity and yield point of anti-freeze MF PAC-LV solutions .................... 56
Figure 5.12.Plastic viscosity and yield point of anti-freeze 0.6% MC M0387 solutions ............. 57
Figure 6.1.Schematic rheogram showing rheological types ......................................................... 60
vii
Figure 6.2.Comparison between measured data and fitted Newtonian model (μ=23 cp) for 0.3%
guar gum anti-freeze system ......................................................................................................... 64
Figure 6.3.Comparison between measured data and fitted Bingham model for 0.3% guar gum
anti-freeze system ......................................................................................................................... 65
Figure 6.4.Comparison between measured data and fitted Power law model for 0.3% guar gum
anti-freeze system ......................................................................................................................... 66
Figure 6.5.Comparison between measured data and fitted API model for 0.3% guar gum antifreeze system ................................................................................................................................. 67
Figure 6.6.Comparison between measured data and fitted Herschel-Bulkley model for 0.3% guar
gum anti-freeze system ................................................................................................................. 69
viii
LIST OF TABLES
Table 2.1. Freezing point (°C) of different alcohols by (%, w/w) ................................................ 15
Table 2.2. Commonly used viscosifiers of drilling fluid .............................................................. 21
Table 2.3. Commonly used filtration control agents of drilling fluid ........................................... 24
Table 3.1. Concentrations of polymer in rheology test ................................................................. 30
Table 4.1. Freezing points and salt-out temperatures for different concentrations of NaCl and
glycerol ......................................................................................................................................... 34
Table 4.2. Freezing points and salt-out temperatures for different concentrations of KCl and
glycerol ......................................................................................................................................... 35
Table 4.3. Freezing points and salt-out temperatures for KCl - NaCl - glycerol solutions .......... 36
Table 4.4. Freezing points and salt-out temperatures for reduced concentrations of the
components ................................................................................................................................... 38
Table 5.1. YP/PV ratio of xanthan gum solutions ........................................................................ 42
Table 5.2. YP/PV ratio of guar gum solutions .............................................................................. 43
Table 5.3. YP/PV ratio of modified starch solutions .................................................................... 45
Table 5.4. YP/PV ratio of M7140 methylcellulose solutions ....................................................... 46
Table 5.5. YP/PV ratio of M0262 methylcellulose solutions ....................................................... 47
Table 5.6. YP/PV ratio of M0387 methylcellulose solutions ....................................................... 48
Table 5.7. YP/PV ratio of MF PAC LV solutions ........................................................................ 49
Table 5.8. Optimum concentration of selected polymer ............................................................... 50
Table 5.9. Apparent viscosity of 0.2% xanthan gum in response to anti-freeze agents ............... 51
Table 5.10. Apparent viscosity of 0.3% guar gum in response to anti-freeze agents ................... 53
Table 5.11. YP/PV ratio of 0.3% guar gum in response to anti-freeze agents ............................. 54
ix
Table 5.12. Apparent viscosity of 1% modified starch in response to anti-freeze agents ............ 54
Table 5.13. Apparent viscosity of 0.5% MF PAC-LV in response to anti-freeze agents ............. 56
Table 5.14. Apparent viscosity of 0.6% MC M0387 in response to anti-freeze agents ............... 57
Table 6.1. Shear stress of 0.3% guar gum anti-freeze system measured in field units ................. 63
Table 6.2. Summary of EAAP of anti-freeze polymer solutions from different models ................ 70
Table 6.3. Engineering data from the well design ........................................................................ 74
Table 6.4. Simulated pump pressure with anti-freeze polymer drilling fluid .............................. 75
Table 7.1. Filtration volumes of polymer solutions ...................................................................... 77
Table 7.2. Filtration volumes of polymer combinations ............................................................... 78
Table 7.3. Filtration volumes of anti-freeze polymer solutions .................................................... 79
Table 7.4. Rheology of anti-freeze polymer solutions .................................................................. 80
Table 7.5. Engineering data from the well design ........................................................................ 86
Table 7.6. Simulated pump pressure with AFP1 .......................................................................... 86
Table 7.7. Simulated pump pressure with AFP2 .......................................................................... 86
Table 7.8. CCI of three anti-freeze polymer drilling fluids under different temperature ............. 86
x
LIST OF SYMBOLS, ABBREVIATIONS, NOMENCLATURES
𝐴𝐹𝑆
=
Anti-freeze solution
𝐴𝐹𝑃
=
Anti-freeze polymer solution
𝐴𝑃𝐼
=
American Petroleum Institute
𝐴𝑉
=
Apparent viscosity
𝐵𝑇𝑂𝐸
=
Billion Tons of Oil Equivalent
𝐶𝐶𝐼
=
Cutting Carrying Index
𝐶𝑀𝐶
=
Carboxymethylcellulose
dp/dL
=
Pressure gradient
𝐸𝑆𝑃
=
Electric submersible pumps
𝑓𝑎
=
Fanning friction factor in annulus
𝑓𝑝
=
Fanning friction factor in drill pipe
𝐻𝐸𝐶
=
Hydroxyethylcellulose
𝐻𝑇
=
High Temperature
𝐼𝑂𝐷𝑃
=
International Offshore Drilling Program
𝑘𝑎
=
Flow consistency index for annular flow
𝑘𝑝
=
Flow consistency index for pipe flow
𝐾
=
Power law constant
𝐿𝐶50
=
Lethal Concentration 50%
𝐿𝐷50
=
Lethal Dose 50%
𝐿𝑃𝐿𝑇
=
Low Pressure Low Temperature
𝑀𝐶
=
Methylcellulose
𝐺𝐼𝑆𝑃2
=
Greenland Ice Sheet Project 2
𝑛
=
Flow behavior index
𝑛𝑎
=
Flow behavior index for annular flow
𝑛𝑝
=
Flow behavior index for pipe flow
𝑁
=
Rotational velocity
𝑁𝐵𝐴
=
n-Butyl Acetate
𝑁𝑁𝑒
=
Reynolds number
xi
𝑁𝑅𝐶
=
National Research Council
𝑂𝐵𝑀
=
Oil Based Mud
𝛥𝑝𝑎
=
Pressure loss in annulus, psi
𝛥𝑝𝑏
=
Pressure loss in bit, psi
𝛥𝑝𝑑𝑠
=
Pressure loss in drill string, psi
𝛥𝑝𝑝
=
Pump pressure, psi
𝑃𝐴𝑂
=
Polyaphaolefin
𝑃𝐻𝑃𝐴
=
Partially-hydrolyzed polyacrylamide
𝑃𝑆𝐴
=
Production Sharing Agreement
𝑃𝑉
=
Plastic viscosity
𝑅𝑂𝑃
=
Rate of Penetration
𝑆𝑀𝑃
=
Sulfonated phenol formoldehyde resin
𝑣𝑎
=
Annular velocity, cp
𝑣𝑝
=
Pipe velocity, cp
𝑊𝐵𝑀
=
Water Based Mud
𝑌𝑃
=
Yield point
𝜌
=
Mud weight
θ600
=
Dial reading at 600rpm
θ300
=
Dial reading at 300rpm
θ100
=
Dial reading at 100rpm
θ3
=
Dial reading at 3rpm
𝜇𝑒
=
Equivalent viscosity, cp
μ𝑝
=
Plastic viscosity, cp
γ
=
Shear rate, s-1
τ
=
Shear stress, lb/100ft2
τ0
=
Yield point, lb/100ft2
Greek symbols
xii
CHAPTER 1: INTRODUCTION
1.1
Arctic oil and gas production potential
For the past few years, drilling activities have increased dramatically in the Arctic regions
of Russia, Canada and Alaska. The Arctic region is considered to be the area with the highest
unexplored potential for oil and gas as well as unconventional hydrocarbon resources such as gas
hydrates (Zolotukhin and Gavrilov, 2011). The US Geological Survey estimated that, in addition
to the existing fields, the Arctic region still has about 13% of the undiscovered oil reserves of the
world, and 30% of the world’s undiscovered natural gas reserves (U.S. Geological Survey, 2008).
The Arctic region refers to the polar area located at the northern-most part of the earth. It consists
of the Arctic Ocean and parts of Eurasia, North America and Greenland. (Belonin and
Grigorenko, 2007) assessed 17 petroleum basins in the circumpolar region and graded them as
high or low potential (Figure 1.1.). In the assessment, the recoverable quantities of conventional
hydrocarbons are estimated at 135 billion tons of oil equivalent (BTOE).
Figure 1.1.Circumpolar belt of hydrocarbon accumulation (Belonin and Grigorenko, 2007)
1
1.2
Challenges in Arctic drilling
The drilling operation in the Arctic is challenged by the specific geological and climatic
conditions: drilling in permafrost and operating under low temperature. Both issues complicate
the drilling operation and cause problems to well stability and borehole cleaning. To address
these issues, an understanding is needed of the characteristics of the structure of permafrost and
its temperature profile.
1.2.1
Structure of permafrost
Permafrost is a highly unconsolidated formation with ice serving as the matrix structure.
Figure 1.2 originally sketched by R. G. Skinner, who relied on the data from excavations in the
Kaminak Lake area, shows the typical configurations of the permafrost surface (Shilts, 1978).
Figure1.2.Three-dimensional diagram of permafrost, Kivalliq, Nunavut, Canada (Shilts,
1978)
The upper section is a thin active layer of unconsolidated sandy and silty sediments. It
seasonally thaws during the summer. The depth range of active layer is from 10cm to 15m
2
(Huggett, 2003). The lower section is seasonally independent and consists mostly of ice lenses
and frozen stratum. The drilling operation in permafrost mostly involves drilling the frozen
stratum, which is a series of strata composed of different kinds of mineral particles, ice cakes,
water and water vapor filled air pockets. While the ice is a main component of the formation, the
fluctuation in ambient temperature and pressure can change the relative proportions of ice and
water, which inevitably triggers the variation of the physical properties of permafrost, such as
compressive strength and plasticity. The less liquid water phase in the permafrost, the higher the
compressive strength and plasticity. Rock with high compressive strength and plasticity resists
the penetration of bit, but also supports well stability (Cui, 1998). The ice contained in rock
pores enhances the bonding of frozen stratum; hence increasing the well stability. The melting of
the frozen stratum compromises well stability and leads to an extremely high rate of penetration
(ROP), which increases the ratio of cuttings load to cuttings removal and generates problems for
hole cleaning. Therefore, supporting the frozen stratum is very important for effective and safe
drilling, while the temperature of permafrost over the drilling operations is a leading factor for
controlling the drilling.
1.2.2
Temperature profile when drilling permafrost
The surface temperature and formation temperature regulates drilling in permafrost.
Most of the time, the surface temperature is defined by local weather condition, as is the case on
Kharyaga, Russia (Figure 1.3). The surface temperature of permafrost drilling ranges from -15°C
to -25°C (Boyer and Szakolczai, 2011).
3
Figure1.3.Outside working time limitation on Kharyaga, Russia (Boyer and Szakolczai,
2011)
Figure 1.4 depicts the average temperature profile with depth of formation in a
permafrost region. The bifurcating red lines at the top show the maximum and minimum annual
temperatures in the active layer. The active layer is seasonally frozen. The middle zone is
permafrost, which is permanently frozen. This zone starts at the depth where the maximum
annual temperature intersects 0°C, and ends at the bottom line where the formation stops
freezing. The lower zone is the formation with temperature that is higher than 0°C.
The change of temperature with depth is described by geothermal gradient. In the region
of North Slope, Alaska, the ice bearing permafrost sequence usually has geothermal gradients
ranging from 1.55 to 1.90 °C/100m. The depth of the permafrost can be as much as 588m. Below
the base of permafrost, the geothermal gradient range is 2.55 to 3.17 °C /100m (Collett et al,
1988). The maximum well depth in North American Arctic region is less than 2000m (IODP,
2011), so the maximum bottom hole temperature of Arctic can be estimated to be lower than
4
70°C. Normally the HT (high temperature) wells begin at 150°C bottom hole temperature
(Belani, 2008). Therefore, the drilling activities in permafrost do not involve high temperature
condition. The drilling operations are challenged by the problem associated with the sub-freezing
temperature up to -25°C.
Figure1.4. Average temperature profile of formation in a permafrost region (Adapted from
Smith, 1975)
1.3
Criteria for drilling fluids designed for Arctic drilling
When drilling into permafrost, the well bottom temperature will increase with the heat
generated by the bit in cracking the rock. Drilling fluid flows from the mud pump through the
standpipe, rotary hose, kelly, drillpipe and drill collar — all the way to drill bit. Flowing through
each section creates frictions and consumes pressure and hydraulic power, hence generates heat.
The drilling cuttings and chips carried by the mud also produce heat by friction and collision.
5
The drilling fluid that flows downward in the drillpipe is kept heated by the fluid that flows
upward in the annulus, while the drilling fluid in the annulus also evolves in the heat transfer
with ambient formation. The heat that transfer into the stratum will not only increase the
temperature up to 0°C, but also melt the ice cement in the rock and weaken the bonding of rocks.
When the drilling fluid temperature in the wellbore is high enough to melt ice bonding, due to
heat transfer, the frozen soil will become unstable and worse condition will follow: i) wellbore
wash out and collapse; ii) mud got frozen inside the borehole; iii) drillpipe got frozen on the
sidewall.
Research shows that the prerequisite for fast and safe drilling operation in permafrost
requires keeping the physical state and temperature condition of the frozen stratum unchanged
(Tang et al, 2002). While the drilling fluid is the key factor for heat transfer in the wellbore, the
temperature of drilling fluid needs to be as close to the ambient formation temperature as
possible, in order to reduce the heat exchange. Therefore, it is necessary to use the drilling fluid
with a low freezing point, which can be achieved by the incorporation of freezing point
depressants (anti-freeze agents) into the drilling fluid.
Having sand and gravel in the upper sections and clay in lower sections characterize the
permafrost formation. The only practical way to support sufficient hole cleaning, especially in
gravel sections, is to increase mud viscosity and gel strength. However, excessive viscosity and
gel strength will also contribute to heat generation in the well, and, hence, thermal instability of
the well, as well as in drilled solids retention and hydrostatic pressure misbalance. The low
temperature itself has a negative impact on viscosity control since most liquids are more viscous
at lower temperature. Thus, viscosity control during drilling permafrost is complicated and
6
requires additional investigation to clarify the rheological and hydraulic characteristics needed
for safe and effective drilling.
The lower zone of permafrost contains a clay section with temperature above 0°C (Fig.
1.4.). In this section, hydration and swelling of clay is not inhibited by temperature. The
hydration of the stratum starts when the formation rocks of wellbore is in contact with water, the
adsorption of water molecular attract the water into the internal structure of stratum, and make
the stratum swell and crack. The solid content of drilling fluid will enhance with increasing of
hydrated drill cuttings. High solids content can reduce the rate of penetration, causes bit balling
and enhance torque and drag, and, hence have a negative impact on drilling performance. High
solid concentration and dispersion could lead to significant increase in mud viscosity and gel
strength, which is undesired. The typical approach to provide wellbore stability is by the use of
the shale inhibitive fluids.
Salty drilling fluids, which usually used for drilling permafrost, have inherent inhibitive
ability. However, inorganic salt not only inhibits the shale section from hydration, it also
prevents the drilling fluid from dispersion of dry bentonite and flocculates or aggregates the prehydrated or pre-dispersed bentonite. On the other hand, the low temperature environment also
significantly suppresses the clay dispersion of drilling fluid. Therefore, we suggest design of
anti-freeze fluid without bentonite, only with complex polymeric systems and required additives
(Non-solid anti-freeze polymer drilling fluid).
From the above, drilling in Arctic region must deal with the issues of heat transfer, well
stability, hole cleaning and drilling efficiency. These specific conditions require specifically
adapted approaches in drilling fluid design and optimization. First of all, drilling fluid with very
7
low freezing point has to be used to maintain temperature balance of the frozen stratum and
avoid getting fluid to be frozen in the borehole (Tang et al, 2002). Second, the anti-freeze drilling
fluid system should be capable to support effective hole cleaning and borehole stability in
permafrost formation. Third, the polymeric system should be applied to makeup non-solid
drilling fluids, which provide good rheological and filtration control under subfreezing
conditions comparable to those under conventional drilling conditions.
1.4
Objectives of study
The main objectives of this research project are:
1.
Design of anti-freeze drilling fluid:
a. Select freezing point reducers;
b. Select low temperature brines (e.g. NaCl, KCl and CaCl2) compatible with
polymer mud;
c. Investigate resistance of variety of polymers to cold conditions and their
rheological behavior in response to low temperature;
2.
Optimize the hole cleaning capacity of the designed anti-freeze drilling fluids;
3.
Select the best-fit rheological model of the designed anti-freeze drilling fluid;
4.
Optimize filtration control of the designed anti-freeze drilling fluids;
5.
Finalize the anti-freeze drilling fluid formulation and test drilling fluid performance under
different temperature.
8
CHAPTER 2: LITERATURE REVIEW
In this chapter, available information regarding arctic drilling engineering and research of
anti-freeze drilling fluid is reviewed. The goal is to document and synthesize information on
anti-freeze drilling fluid composition and whether previously proposed formulations of drilling
fluid can be used for Arctic drilling. The rationale for drilling fluid component selection is
discussed.
2.1
The development of Arctic drilling
The first site of oil discovery in the far North of Canada was in 1920, in Norman Wells,
Northwest Territory, along the Mackenzie River about 85-90 miles south of the Arctic Circle.
Alexander Mackenzie claimed that he had discovered oil from the riverbank. Later on, R.G.
McConnell of the Geological Survey of Canada confirmed the existence of oil seepages. Imperial
Oil (ESSO) acquired the claims and sent two geologists in 1918-1919, who recommended
drilling. The drilling crews dug into the permafrost with pick and shovel, they struck the oil at
240m. This discovery indirectly contributed to exploration in Alberta after the First World War
and the decision to drill Leduc No.1 on February 1947, which is the geological key to Alberta’s
most abundant reserves (Brown, 2009).
The exploration for hydrocarbons in the Arctic islands of Canada has a more recent history.
The first exploratory well in the Arctic islands was drilled in 1961, Winter Harbor #1 well on
Melville Island. The operator was Dome Petroleum. Since then, more than 140 wells have been
drilled. In 1969, Panarctic Oil Ltd. made the first major discovery in the Arctic Islands at Drake
Point, which is probably Canada’s largest gas field.
9
The first Arctic offshore wells in North America were drilled in 1969 using artificial
islands as drilling platforms in the Beaufort Sea. Following the boom of exploration activities in
the 1970’s and 1980’s, only a few wells were drilled after 1993. Over the last 37 years, more
than 200 exploration and exploitation offshore wells have been drilled in the US and Canadian
Arctic north of the Bering Strait. Five of these wells were drilled in the Chukci Sea, about 90
wells in the Canadian Beaufort Sea and Mackenzie Delta, about 70 wells in the US Beaufort Sea
near the Alaska coast (including 31 wells in Federal waters), and about 40 wells in the straits and
channels between the Canadian High Arctic Islands (Matskevitch, 2006). The Beaufort Sea
exploration developed a variety of new technologies. The most innovative one is Kulluk, the
circular vessel designed for extended-season drilling operations in Arctic waters.
In 1995, Total, Statoil and the Russian Federation signed a Production Sharing Agreement
(PSA) for the exploration and exploitation of their first Arctic project, the Kharyaga oil field.
The field is located 60 km to the north Polar Circle in the Nenets Autonomous Okrug, Russia.
Since October 1999, the project has completed three phases and new wells were drilled. By
August 2011, there were 26 wells in producing oil with Electric Submersible Pumps (ESP) and
11 Water Injection Wells on the field (Fletcher, 2011)
In January 2002, Canada, US and Japan have cooperated to drill the well Mallik 2L-38 in
Canadian Mackenzie Delta. The data from the well has demonstrated that there are natural gas
hydrates reserved beneath the permafrost. After that, India, International Continental Scientific
Drilling Program (ICDP) and Germany have joined the research. By June 2002, they have
completed five wells (Mallik L-38, Mallik 2L-38, Mallik 3L-38, Mallik 4L-38, and Mallik 5 L38) at Mackenzie Delta in northwestern Arctic area of Canada. Various technologies were
applied for the first time, including the pressure temperature memory gauge in coring system,
10
running fiber optics networks to temperature sensing cables and production testing. These were
all confirmed effective for the investigation of the natural hydrate (Takahashi et al, 2003)
In March 2003, Anadarko Petroleum, Maurer Technology and the US Department of
Energy started the investigation of Natural gas hydrate in North Slope of Alaska. They drilled the
first exploration well ---“Hot Ice No.1”, south of the Kuparuk River field. The project resulted in
a wide range of technical innovations, such as advances in permafrost drilling and coring
techniques, the demonstration of the stability and exceptional environmental performance of the
Arctic Platform, and the feasibility of a fully instrumented mobile core analysis lab (Williams et
al, 2003)
The great potential for hydrocarbon resources has led to growing drilling activities in
Arctic, which is an incubator of various technical innovations, but mostly is about drilling
equipment and facilities. However, the drilling fluid for Arctic drilling, one of the most
important factors of drilling operation is still under investigation. Reviews on the current
achievements in this field are presented below.
2.2
2.2.1
The development of anti-freeze drilling fluid
Types of drilling fluids for arctic drilling
Drilling fluid is an essential element of rotary drilling because it is responsible for
cleaning the bottom of the hole from cuttings generated by the bit and carrying them to the
surface; cooling and lubricating the bit and the drill strings; offset the formation pressure and
maintaining the stability of uncased borehole; forming thin and flexible filter cake to prevent
fluid infiltrate into formation. Moreover, drilling fluid should be designed and maintained to
avoid injuring drilling personnel or damaging the environment; to avoid excessive cost; and
11
avoid damaging the sustainable hydrocarbon production from the formation. Missing one of
these functions makes the drilling ineffective. Poor drilling fluid design and/or maintenance may
also result in detrimental impacts on the rig itself, rig personnel and environment.
When drilling permafrost, the drilling fluid must meet additional requirements. The
presence of water in drilling fluid is detrimental for wellbore stability under these conditions.
Along with traditional problem of shale swelling and dispersion due to water infiltrate to the
formation, the water infiltrate will melt ice bonding the frozen stratum which will lead to
collapse of the wellbore wall. Moreover, water-based drilling fluid may be frozen in the wellbore
and may initiate freezing of drill strings. Under these circumstances, oil based mud (OBM)
seems to be an effective solution since clay particles do not hydrate or swell when in contact
with oil and the ice that contained in the frozen stratum does not dissolve in oil, which helps
maintain the well stability (Patel, 2007). Freezing points for oils vary around -18 °C depending
on oil composition. However, oil viscosity significantly increases with decreasing temperature, a
property that can have negative impact on drilling performance. Moreover, the oil base of the
drilling fluid has a negative impact on the environment due to hydrocarbon toxicity and low
biodegradability.
The arctic environment is vulnerable to oil waste and spills, even low-toxic and
biodegradable synthetic oils, due to slow recovery of aquatic and terrestrial ecosystems in cold
and highly seasonal conditions as well as the inherent difficult conditions for biodegradation due
to toxicity. Cold conditions provide very slow, if any, natural biodegradation and results in long
term contamination that will affect ecosystems for decades. The accumulation of hydrocarbons,
phenolic compound and heavy metals included in the different mud formulations in aquatic and
terrestrial species that are consumed by humans increases the negative impact on human health
12
(Ogeleka, 2013). To avoid these problems, complicated waste and spill treatment technologies
are required for Arctic operations that, as said before, cannot be deployed in Arctic region due to
climate conditions and sensitivity of the ecosystem. Hence transportation of waste is required to
far-away treatment facilities that significantly increase cost of drilling operations. Therefore,
cost-effective and environment-friendly water based mud (WBM) is desirable substitution for oil
based mud (OBM) in permafrost drilling. As mentioned before, WBM is a challenging option
when drilling in permafrost because of water freezing at operating conditions and its interference
with wellbore stability. Another problem is poor dispersibility of solid components such as
bentonite and barite in cold water. The possible solutions to these problems are (i) anti-freeze
water base drilling fluid and (ii) no-solid polymer mud. This chapter presents up-to-date research
and field experience of application of anti-freeze agents and polymers in drilling fluids for
drilling permafrost.
2.2.2
Antifreeze agents for drilling fluids
The weather condition of the Arctic requires that the drilling fluid maintain their
properties to temperatures of at least -20°C as discussed in Chapter 1. The freezing point,
rheology, filtration control and shale inhibition are four factors affecting the performance of
arctic drilling fluid. A number of researchers investigated the chemicals and polymers to support
these functions of the arctic drilling fluid.
2.2.2.1 Alcohols
Alcohols are a main category of anti-freeze agents. Methanol, ethanol, ethylene glycol,
propylene glycol and glycerol are commonly used for the freezing point depression in
automobile industry. Alcohols form strong hydrogen bonds with water molecules that disrupt the
13
crystal lattice formation of ice that makes them effective anti-freeze agents. Methanol and
ethanol provide the lowest freezing point: -38°C and -30°C, respectively, when 40% of alcohol is
used (Table 2.1). However, the use of methanol and ethanol is dangerous because of their low
boiling points and high flammability. Besides, methanol is highly toxic to humans. Ethylene
glycol and propylene glycol are less effective: they provide freezing point depression up to -24°C
and -21°C, respectively, when 40% of alcohol is added (Table 2.1). However, at this
concentration they are also toxic for humans as well as aquatic and terrestrial ecosystems. In
particular, 1400 -1600 mg of ethylene glycol per kg of human weight were reported to be lethal
for human. The LD50 of rats is 4000 mg/kg (Honeywell, 2006). An LD50 represents the
individual dose required to kill 50 percent of a population of test animals. The lower the LD50
dose, the more toxic the chemical. The effect of ethylene glycol on terrestrial ecosystems is
softened by quick biodegradation both aerobically and anaerobically (ATSDR, 2010). Propylene
glycol is less toxic, but it still causes harm to aquatic species. The LC50 of algae is 18340mg/L
(UNEP, 2001). An LC50 value is concentration of the chemical in air that kills 50% of the test
animals during the observation period. Glycerol has very low toxicity (LD50 of rats is
12600mg/kg) and is commonly used in the food industry. Glycerol is readily biodegradable and
not significantly bioaccumulate and is not expected to be toxic to aquatic ecosystems (Hudgens
et al, 2007). However, 45 – 50 % of glycerol was reported to be required to reduce the freezing
point to the desired -20°C (Pescatore, 2003). Nevertheless, glycerol may be considered as
promising anti-freeze agent for drilling in Arctic because of its environmentally friendly nature,
low cost and high availability.
14
Table2.1. Freezing point of different alcohols (Adapted from Pescatore, 2003)
Methanol
(%, w/w)
0
8.1
14
20.6
25
29.2
33.6
38
40
Freeze
Freeze Ethylene Freeze Propylene Freeze
Freeze
Ethanol
Glycerol
point
point
glycol
point
glycol
point
point
(%,w/w)
(%,w/w)
(°C)
(°C)
(%,w/w)
(°C)
(%,w/w)
(°C)
(°C)
0
0
0
0
0
0
0
0
0
-5
6.8
-3
14
-5
16
-5
22.6
-4.8
-10.2
20.3
-10.6
24
-10
24
-9
33.3
-11
-15.6
24.2
-14
32
-16
32
-14
40
-15.4
-21.6
29.9
-18.9
36
-20
40
-21
45
-18.8
-25
33.8
-23.6
40
-24
50
-23
-30
46.3
-33.9
-35.6
-38
2.2.2.2 n-Butyl Acetate
In the Greenland Ice Sheet Project 2 (GISP2) headed by Polar Ice Coring Office,
University of Alaska, n-Butyl Acetate (NBA) was used as a choice of drilling fluid. The freezing
point of pure NBA was reported to be -77°C. However, the use of NBA presents a number of
challenges due to its aggressive solvent nature, toxicity and flammability. It is also difficult to
control NBA performance because it decomposes in the presence of water (Gerasimoff, 2006).
2.2.2.3 Inorganic salts
Inorganic salts are promising agents for anti-freeze drilling fluid. Increasing concentration
of the salt decreases the freezing point of the solution. According to the industry standard from
the National Research Council (NRC, 1991), a brine solution with 23% NaCl creates a freezing
temperature of -21°C on the roads which is lower than surrounding ice and snow (Brewer et al,
2005). Drilling fluids containing 20-23% NaCl in polymer mud are most commonly used in deep
water drilling and allow safe drilling in cold water up to depth of 2500m (Ning et al., 2009).
15
Chen (2008) investigated the freezing point of the solutions of NaCl and sodium formate
(NaCOOH) to design the formula of anti-freeze drilling fluid for exploration of plateau natural
gas hydrates. The freezing point was depressed to -17°C with NaCl and to -14°C with NaCOOH
when 20% salt was used in the drilling fluid (Chen, 2008). Researchers of the Russian Saint
Petersburg State Mining Institute have attempted to use salts to reduce freezing point in emulsion
drilling fluid. To enhance the anti-freeze ability of drilling fluid, Na2Br2O7 (2% and 6.4% w/w),
NaNO3 (20% w/w) and Na2CO3 (10% and 20% w/w) have been added into the system. However,
the lowest freezing point of the emulsion drilling fluid observed was provided by 20% NaNO3
and reached -8°C, which is not low enough for the arctic drilling environment (Tang, 2002).
Wang, et al (2009) investigated the possibility of application of 15% NaCl (w/w) anti-freeze
solution in non-solid polymeric drilling fluid. After adding NaCl solution, the freezing point of
vegetable gum and xanthan gum was depressed to -12°C. At fixed temperature, addition of NaCl
decreased viscosity of both polymeric solutions. The salt-tolerant viscosifier, FA, was added to
eliminate the effect of salts on viscosity of gums (Wang, 2009). FA prevents the viscosity from
decreasing in the presence of salt. Further research is needed to investigate the agent that can
slow the increase of viscosity of natural gum under low temperature. The freezing point also
needs to be depressed (Wang et al, 2009). Bland (1994) investigated the depression of freezing
points of drilling fluid surfactant (10% polypropylene glycol) with addition of 23% NaCl. The
freezing point of -9.4°C was achieved (Bland, 1994).
Therefore, while the freezing point of NaCl water solution is low enough to drill
permafrost, mixing of NaCl with drilling fluids or drilling fluid components, in many cases, does
not allow enough freezing point depression. Moreover, high salinity can deteriorate drilling fluid
properties, e.g., viscosity as determined by Wang (2009, above). High salinity also prevents
16
hydration and dispersion of bentonite in drilling fluid making it useless for viscosity, gel strength
and filtration controls. As shown in Figure 2.1, the maximum swelling rate of bentonite sharply
decreases with increasing NaCl concentration from 0 to 1.0 M (Shirazi, 2011). Thus, application
of highly salty anti-freeze agents may interfere with functionality of a drilling fluid.
Figure2.1. Effect of NaCl concentrations on maximum swelling rate of clay (Shirazi, 2011)
Another problem is the effect of the solvent temperature on the solubility of salts.
Lowering temperature decreases the maximum solubility (saturation level), and hence causes
precipitation of salts, which may have negative impact on functionality of the drilling fluid (John,
1999). Figure 2.2 shows the solubility curves of different salts (Hill, 2005). According to this
figure, sodium chloride’s solubility only slightly increases from 0°C to 100°C, while the
solubility of other salts changes dramatically. If we assume that the solubility of NaCl will
slowly decreased below 0°C, 23% NaCl (providing -20°C) seems to be acceptable for drilling
17
operations. However, there is no available information about saturation level of NaCl at this
temperature, and additional research is required to clarify this issue.
Figure2.2. Solubility curves of some salts in water (Adated from Hill, 2005)
Aside from temperature, pressure is another factor that significantly changes the
solubility of salts in water. Experiments have been conducted to verify the effect of pressure
under thousands of atmospheres. The regularity in behavior is indicated by pressure- solubility
curves. For example, increasing pressure slightly increases the solubility of K2SO4 in water.
After the peak of the curve, the solubility decreases slightly with pressure (Adams, 1932). The
solubility of NaCl has the similar shape in curve but the changes are smaller (Adams, 1931).
18
High salinity is also detrimental for growth and development of plants and
microorganisms. The response of plants to excess NaCl is complex and involves changes in their
morphology, physiology and metabolism (Hilal, 1998). Even 10 % NaCl was determined to
cause death of plants and significantly reduce microbial activity such as biodegradation of
hydrocarbons (Brewer, 2005). Thus, high salinity drilling waste will have potential negative
impact on terrestrial and fresh water ecosystems as well as create a problem in drilling waste
detoxification (biodegradation). Thus the salt concentration of drilling fluid needs to be
maintained as low as possible, to minimize the detrimental impact of drilling fluid performance,
waste management and the permafrost ecosystem.
2.2.2.4 Complex anti-freeze agents
A possible way to solve the problem of high salinity of anti-freeze solution is to
supplement it with other anti-freeze agents. The main goal of this research is to develop complex
anti-freeze agent with reduced concentrations of the individual components. Early attempts to
this goal were performed by Zhan (2009) who determined that the mixture of 7.5% (w/w) NaCl
and 25% (w/w) ethylene glycol can reduce the freezing point of drilling fluid to -20°C which
otherwise requires 23% NaCl or 36% ethylene glycol when used individually. Thus, the
concentrations of NaCl and ethylene glycol were reduced to level acceptable for environment
and human health. Despite the good anti-freeze characteristics, this combination of chemicals
could not provide proper hole cleaning and shear thinning behavior because it behaved as a
Newtonian fluid when temperature above 0°C (Zhan, 2009). The present study aims further
investigation of complex anti-freeze agents for drilling fluids. For this purpose, glycerol was
selected to be reinforcing anti-freeze agent because of its high availability, reasonable cost, very
low toxicity and high freezing point depression capability. Glycerol will be tested for reduction
19
of effective (with respect to freezing point depression) concentration of NaCl along with KCl
necessary for inhibitive activity (in respect to swelling of the reactive shale) of drilling fluid. The
proper rheology performance of drilling fluid with the presence of glycerol and salts will also be
investigated.
2.2.3
Polymer for anti-freeze drilling fluids
Due to the impossibility of using bentonite for viscosity and filtration control in the anti-
freeze drilling fluids, the anti-freeze drilling fluid should not include clay, which has to be
replaced with polymers recovering drilling fluid viscosity and filter cake formation. While a
broad variety of polymers are used in drilling fluid for viscosity and filtration control, their
application in anti-freeze drilling fluids raises the challenge: compatibility of polymers with salts,
solubility in cool water, tolerance of polymer’s properties to decreasing temperature and toxicity
against sensitive ecosystem. The purpose of this part of the literature review is to select the
polymers acceptable for anti-freeze drilling fluids.
2.2.3.1 Viscosifier
Table 2.2 lists commonly used viscosifiers of drilling fluids. All of these polymers are
non-toxic, work up to 80°C - 150°C. Xanthan gum, guar gum, methylcellulose,
hydroxyethylcellulose (HEC) and carboxymethylcellulose (CMC) were reported to be soluble in
cool water. The first three components were also reported to be compatible with salts that make
them potential candidates for anti-freeze drilling fluid development.
Xanthan gum is a polysaccharide composed of pentasaccharide repeat units, comprising
glucose, mannose, and glucuronic acid that secreted by the bacterium Xanthomonas campestris.
It is a commonly used thickening agent in drilling fluids. At moderate temperature, xanthan gum
20
exists in aqueous solution in a naturally ordered conformation. On increasing the temperature of
an aqueous solution of xanthan gum, the viscosity increases suddenly, suggesting a
conformational change. A xanthan gum solution in presence of salts like NaCl and KCl can
maintain its ordered structure and viscosity up to 100°C. Xanthan gum was used in the drilling
fluid for Imperial Oil’s early arctic operations along with bentonite and KCl. Laboratory and
subsequent field tests proved that this system have depressed freezing point (-6°C) and good
rheological properties (Kljucec et al, 1974). A non-solid polymer drilling fluid has been designed
and implemented in the Prudhoe Bay, Alaska. The fluid was composed of clarified xanthan gum,
starch, KCl and CaCO3. The clarified xanthan gum was used as viscosifier, while the starch
provided filtration control. The experiment verified that the fluid was non-damaging and shale
inhibitive. Effective cutting transport was also achieved (Beck, 1993).
Table 2.2.Commonly used viscosifiers of drilling fluid
Polymer
Solubility
Range of pH
Tolerance
Salt
Compatibility
Toxicity
Temperature
limitation
Xanthan gum
Soluble in cold
water
1-11
Y
N
120°C
HEC
Soluble in cold
water
6-8.5
Precipitate in
salt water
N
107 - 121°C
CMC-HV
Soluble in cold
water
9-11
Not tolerable
to Calcium
N
130 - 150°C
5-7
Y
N
80 - 95°C
3-11
Y
N
80 - 90°C
Guar gum
Methylcellulose
Soluble in cold
water
Dissolves
easily in cold,
hardly in hot
water
21
Guar gum is a naturally occurring polysaccharide composed of repeat units of galactose
and mannose in a ratio of approximately 1:1.6. Guar gum is extracted from the endosperm of the
seeds of the legume plant, which grows in India as a food crop for animals. Guar gum is highly
soluble and stable. It is not affected by pH or ionic strength (Mudgil et al, 2014). Guar gum
shows shear-thinning behavior and is very thixotropic in concentration above 1%. A very small
quantity of guar gum generates great viscosity, which is why guar gum is the principle
thickening agents to drilling fluids and fracturing fluids. The application of guar gum for low
temperature drilling is unknown. But, Wang (2009) investigated application of vegetable gum in
anti-freeze drilling fluid in the exploration of natural gas hydrate in Tibetan plateau region.
Experiments were conducted to test the rheological performance of the designed drilling fluid.
The components of the mud were selected as vegetable gum, NaCl, NaOH and FA. Vegetable
gum was used as viscosifier; FA is a newly invented agent to reduce the effect of salt on the
polymer rheology. The test result showed that the plastic viscosity of drilling fluid has increased
from 30 mPa∙s to 55 mPa∙s when temperature has dropped from 25°C to -10°C, which is
acceptable in drilling fluid operation (Wang et al, 2009)
Methylcellulose (MC) is the mostly used thickener and emulsifier, which easily absorb
moisture. MC is derived from cellulose, but does not occur naturally. It is produced by treating
cotton with an alkali. MC has unusual viscosity response to temperature. It is a thermo-reversible
gelling agent: MC gelifies when heat is applied; but loses gel capacity and becomes liquid when
it is cooled down. At the liquid state, the viscosity of MC solution decreases with increase of
temperature; while at gel state, it increases as temperature increases. This property of MC makes
it a potential candidate for compensation of viscosity changes of the most other polymers in
response to temperature, which are opposite to MC response.
22
2.2.3.2 Filtration control agent and shale inhibitor
In the drilling process, the infiltration of drilling fluid into the formation may cause the
hydration and swelling of shale section, which results in damaging the permeability of the pay
zone. The main goal of a filtration control agent is forming low permeable, thin and
compressible filter cake, which minimizes the infiltration of drilling fluid into formation. Some
filtration control agents also have shale inhibitive ability. Table 2.3 lists commonly used
filtration control agents of drilling fluid. Similarly to viscosifier, the criteria for selecting
filtration control agents for drilling permafrost are solubility in and tolerance to cool water,
tolerance to salts and low or no toxicity. With exception of partially hydrolyzed polyacrylamide
(PHPA), all listed polymers are soluble in cold water. Most of them, except for sulfonated phenol
formoldehyde resin (SMP), are non-toxic. Among them, methylcellulose, PAC and modified
starch are compatible with salts and may be a candidate for anti-freeze drilling fluids.
Starch is a polysaccharide consisting of glucose units joined by glycosidic bonds extracted
from crops and corns. It is insoluble in water below 50°C, but it begins to swell when heated
over 55°C until a colloidal solution is formed. Starch can be modified to increase its cold-water
solubility, tolerance to salts and freezing, decrease or increase its viscosity. Modified starch, also
called starch derivatives, is prepared by physically, enzymatically, or chemically treating native
starch to change its properties (Amani et al, 2005). Modified starches are used in drilling fluids
and completion fluids control fluid loss and enhance the coagulation stability of clay particles in
drilling fluids. Filtration control using starch is based on two mechanisms: (i) the starch particles
absorb the free water, which decrease the water content of drilling fluid; (ii) the bladder formed
on the boundaries of the drilling fluid can get into the cracks of mud cake, so the channel for
water to the mud cake is blocked.
23
Table2.3. Commonly used filtration control agents of drilling fluid
Chemical
Solubility
Range of pH
Tolerance
Salt
Compatibility
Toxicity
Temperature
limitation
Methylcellulose
Dissolves
easily in cold,
hardly in hot
water
3-11
Y
N
80 - 90°C
PAM
Not soluble in
glycerol
8-11
Not dissolve in
salt water
N
120°C
Na-CMC
Soluble in cold
water
6.5-11
Y
N
80°C
PAC-141
Soluble in cold
water
3-11
Y
N
180°C
PHPA
Insoluble in
water at 20 °C
10-10.5
Y
N
180 - 200°C
KHm
Soluble in
water
9-10
Y
N
180°C
SMP
Soluble in cold
water
7-9
SMP-1, 13%;
SMP-2,
Saturated.
Y
350°C
Modified starch
Soluble in
water
6.5-11.5
Y
N
280°C
Modified polyanionic cellulose – low viscosity (MF PAC-LV) is a cellulose derivative
that has similar structure and properties to carboxymethylcellulose. MF PAC-LV is purified
high-grade low molecular weight polymer, which is normally used as a combined filtration
controller and minimal viscosifier in fresh and salt water based drilling fluid systems.
Several investigations have been conducted into novel drilling fluid for the exploration of
natural gas hydrate in Arctic and offshore. The temperature sensitivity of different polymers has
been investigated. The comparison and analysis were made on the influence of molecular
24
structure of PAM, PHPA, PAC-141, Na-CMC and KHm. These polymers were used as filtration
control agents and shale inhibitor as well. The results indicated that the low temperature
tolerance of the above mentioned polymers could be listed in order from low to high: PAC-141 <
PHPA < PAM < Na-CMC < KHm, which means as temperature decreases, the viscosity of PAC141 solution has increased the least (Yang, 2011). The application of 3% formate in hydrates
inhibitive polymeric drilling fluids allowed reducing freezing point to -5°C ~ 15°C, but had no
significant impact on polymers’ rheology. Addition of NaCl and KCl inhibitors also had little
effect on polymer rheology. The polymers used in this drilling fluid are 3% SK-2, 0.2% KPAM,
0.1% PAC- LV, 2% SMP-2 and 0.3% modified starch (w/w) (Ning, 2009).
2.2.4
Candidates of drilling fluid component
Through the above research, the inorganic salts and glycerol were selected as the
components of anti-freeze agent. To formulate an efficient anti-freeze agent, the freezing point
and saturation level of the salt, glycerol and their combination were investigated. The polymer
candidates for anti-freeze drilling fluid component were selected to be xanthan gum, guar gum,
modified starch, MF PAC-LV and methylcellulose. To select the desirable viscosifier and
investigate the hole cleaning ability of designed drilling fluid, the selected polymers were tested
for their rheological behavior, hole cleaning and filtration control capacity under low
temperature and in the presence of anti-freeze agent.
25
CHAPTER 3: METHOD OF RESEARCH
3.1
Overview
This chapter describes the methodology used to conduct experiments aiming to determine:
1. The optimum combinations of anti-freeze agents (inorganic salt and glycerol
combinations) and their freezing point;
2. The rheological properties of polymeric system in response to different temperature;
3. The influence of the anti-freeze agents on the rheology and filtration of polymeric system;
The general approach consisted in testing the freezing point and saturation temperature of
inorganic salt solutions combined with glycerol. The formulation of anti-freeze agent was then
optimized. The rheological and filtration parameters of polymeric systems were measured. The
influence of anti-freeze agent on the rheological and filtration properties of drilling fluid was
determined. The best-fit rheological model of designed drilling fluid is selected for accurate
calculation of the pressure loss and hydraulics optimization.
3.2
Experimental procedure for freezing point and salt solubility of anti-freeze agents
The optimization of anti-freeze agent aims at getting the combination of inorganic salts
and glycerol that allows drilling fluid do not freeze or do not precipitate (salt-out) at the desired
temperature level (-20°C) at lowest salts concentrations. Normally, when the temperature drops
below the freezing point of a salt solution, ice will form in the water phase. Moreover,
decreasing the temperature decreases the solubility of salt. Therefore, the experiment for testing
the freezing point and salt-out temperature of anti-freeze agent made of inorganic salt and
glycerol were designed.
26
The tested inorganic salts were NaCl, KCl and CaCl2. Each of salts at mass concentration
(m/v) of 0%, 10%, 20% and 30% was mixed with glycerol at mass concentration (m/v) of 0%,
10%, 20% and 30%. Each group of mixed solution was tested for three replicates. Three
deionized water replicates were applied as control group. The challenge solutions were prepared
at room temperature and then treated at different temperature points: 25°C, 20°C, 15°C, 10°C,
5°C, 0°C, -3°C, -6°C, -9°C, -15°C and -20°C. At each temperature point, the solutions were
incubated for one hour. The salt precipitation and ice formation in solution were visually
monitored before changing the temperature. The combinations that did not precipitate below 20°C and had the freezing point lower than -20°C, were selected as potential candidate for antifreeze drilling fluid.
3.3
3.3.1
Rheology test of anti-freeze polymer systems
Experiment for the rheology test of polymer systems at different concentrations
In drilling operations, rheological properties indicate the character of deformation and
flow of drilling fluid. The drilling fluid behavior can be evaluated with the application of
rheological properties in solving problems of hole cleaning, mud treatment, hydraulics
calculations and so on. The character is usually described by the parameters: Apparent Viscosity
(μa), Plastic Viscosity (μp) and Yield Point (τ0).
Viscosity is a property that indicates the resistance of drilling fluid to flow, defined as the
ratio of shear stress to shear rate. Apparent viscosity is the viscosity measured at a given shear
rate at a fixed temperature. Most drilling fluids exhibit plastic behavior, which can be described
by Bingham model:
𝜏 = 𝜏0 + 𝜇𝑝 𝛾 …………………………………………………………………...……………. (4.1)
27
Where: 𝜏 - shear stress, lb/100ft2; γ - shear rate, s-1; μp - plastic viscosity, cp; τ0 - Bingham yield
point, lb/100ft2.
Plastic fluids require a certain value of shear stress for initiating flow, which is
characterized by yield point. Plastic viscosity is the slope of the shear stress/shear rate curve
above the yield point. It represents the viscosity of a mud based on the Bingham model when
extrapolated to an infinite shear rate. The ratio of the yield point to the plastic viscosity (YP/PV
ratio) is a measure of flattening the flow profile and by this means improving the hole cleaning.
Higher YP/PV ratio provides better cuttings transport in laminar flow.
To test the rheological parameters of designed drilling fluid systems, a FANN Model 35
Viscometer was used in the experiment. The FANN Model 35 viscometer is a rotational
instrument powered by an electric motor. The test fluid is contained in the annular space (shear
gap) between two concentric cylinders. The outer cylinder or rotor sleeve is driven at a constant
rotational velocity. The rotation of the rotor sleeve in the fluid sample produces a torque on the
inner cylinder or bob. A torsion spring restrains the movement of the bob, and a dial attached to
the bob indicates displacement of the bob.
A schematic diagram of the direct indicating viscometer is shown in Figure 3.1. The
deflection in degrees of the bob is read from the graduated scale on the dial. The viscosity of the
samples can be measured at the rotational velocity of 3, 6, 100, 200, 300 and 600 rpm. Shear rate
is proportional to rotational velocity. According to the dial reading at different rotational velocity,
the rheological parameters (PV and YP) calculation will adopt the following formula:
γ = 1.703N ………………………………………………….………………………..…….… (4.2)
28
μp = θ600 − θ300 ………………………………………………...…..……...………………. (4.3)
τ0 = θ300 − μp ………………………………………..…………………………...………...... (4.4)
Where: γ - shear rate, s −1 ; N - rotational velocity, rpm; θ600 - dial reading of 600rpm, θ300 - dial
reading of 300rpm, μp - Plastic Viscosity, cp; τ0 - Bingham Yield Point, lb/100ft2.
Figure 3.1. Schematic diagram of the Fann Model 35 viscometer
Several polymer solutions are selected as the base fluid: xanthan gum, guar gum, low
viscosity modified polyanionic cellulose (MF PAC-LV), modified starch and methylcellulose
(M0262, M0387, and M4170). The product data sheets of the polymers are listed in Appendix.
For each polymer, the commonly used concentrations in drilling fluid were investigated, and
gradual increase in concentration (Table 3.1) is applied to reach desired values of PV and YP.
The desired concentration of polymer solutions were prepared by dissolving of the
polymer in water by stirring of the mixture with the magnetic stirrer at 1000 rpm until the
polymer is fully dissolved. The polymer solution in each concentration was incubated at
29
temperature points ranging from room temperature to 0°C for about an hour at each point. The
temperature points are 25°C, 15°C, 10°C, 5°C and 0°C. Once the thermometer indicated that the
solution temperature is constant, the dial readings were performed by viscometer and rheological
parameters were calculated. The concentration (m/v) of each polymer solution, which provided
the highest ratio of yield point over plastic viscosity (YP/PV ratio), was considered as the
optimum concentration and was, selected to apply in the next sets of experiment.
Table 3.1.Concentrations of polymer in rheology test
3.3.2
Polymer
Concentrations
Xanthan gum
0.2%, 0.3%, 0.6%, 1%, 1.2%
Guar gum
0.3%, 0.5%, 0.9%, 1.3%
MF Starch
1%, 1.5%, 2%
MF PAC-LV
1%, 1.2%
M7140
2.4%, 3%, 3.6%
M0262
1%, 1.2%
M0387
0.6%, 0.8%, 1%
Rheology test of polymer in presence of anti-freeze agent
For the selected polymer solutions at optimum concentration from above experiments,
their rheological behavior under low temperature is needed. The compatibility of polymer with
anti-freeze agent is another issue that needs to be considered for designing the drilling fluid.
In the experiments of Section 3.2, the formulation of anti-freeze agent was optimized.
The anti-freeze agent was applied to test the behavior in mixing with polymer solutions. The
polymer of desired concentration as above was mixed with the anti-freeze agents determined.
30
The following procedure was followed: The mixed solutions were placed at temperature
points ranging from room temperature to -20°C for about two hours at each point. The
temperature points were 25°C, 0°C, -10°C and -20°C. After exposure to desired temperature, the
salt precipitation (salt-out) and ice formation were monitored and the rheological parameters
were calculated according to Fann viscometer readings.
3.4
Experiments of filtration of anti-freeze polymer systems
Filtration property is described by the volume of filtrate that discharged by API filter press
in 30 minutes. Good filtration control is indicated by low filtrate volume. Low-pressure filter
press consists of a mud reservoir mounted in a frame, a pressure source, a filtering medium, filter
press with CO2 and a graduated cylinder for receiving and measuring filtrate. When starting the
measurement, a working pressure of 100 psi is applied. The filtrate flows through the filter paper
that has an area of 7.1-in2. The volume of filtrate can be indicated from the receiving cylinder. A
schematic of Fann Model 300 Low Pressure Low Temperature (LPLT) Filter Press is shown in
Figure 3.2.
31
Figure 3.2. Fann Model 300 LPLT Filter Press
From the above experiments, the optimum concentrations of polymer solutions have been
selected. Selected polymer solutions alone or in combination with anti-freeze agents were tested
in filtration tests. The volume of filtrate was measured. The mixture of polymer and anti-freeze
agent that provided the lowest filtration was then tested to analyze their rheological properties as
above. At the end of the experiments, the optimized anti-freeze polymer system was selected as
the one that provided the best rheology and lowest filtrate.
32
CHAPTER 4: DESIGN OF ANTI-FREEZE BASE FOR ARCTIC DRILLING FLUID
This chapter presents the results of preliminary experiments aiming at the selection of
suitable agents for a complex anti-freeze composition for drilling fluids. For this purpose,
glycerol was selected to be the reinforcing anti-freeze agent. Tests were conducted to investigate
the reduction of concentrations of NaCl and KCl while maintaining an effective freezing point
depression. CaCl2 solutions were also tested, but precipitation was observed under all tested
conditions, and thus was not considered as a potential freezing point depressant.
4.1
Freezing and salt-out temperature for NaCl and glycerol
Table 4.1 shows precipitation (salt-out) and freezing temperatures for NaCl-glycerol
solutions as a function of components’ concentrations and preparation temperature. Salt-out was
observed for the solution of 30% NaCl -30% glycerol and 30% NaCl -20% glycerol at the room
temperature, for the solution of 30% NaCl -0% glycerol at 0°C and for the solution of 30% NaCl
-10% glycerol at 5°C. Figure 4.1 shows the pictures of salt solution under different status. From
left to right, the dissolved solution, ice crystal and salt precipitates can be easily identified. When
the temperature dropped at the freezing point of solution, the solution start to freeze and form ice
crystal. If the concentration of solution is higher than its saturation level, the undissolved salt
will precipitate out and settle down at the bottom of the tube.
The control solution (distilled water) froze at a temperature of 0°C. 10% and 20% glycerol
and 10% and 20% NaCl froze at -9°C. The solution of 10% NaCl -10% glycerol, 10% NaCl -20%
glycerol and 20% NaCl -10% glycerol froze at -20°C. Ice formation at -20°C was prevented only
by 20% NaCl-30% glycerol, 20% NaCl - 20% glycerol and 10% NaCl-30% glycerol solutions.
Since the working temperature for permafrost drilling is not lower than -20°C, this range is
33
enough to test the anti-freeze ability of the solution. Thus, the latter solutions are considered as
candidates for anti-freeze drilling fluid.
Table 4.1.Freezing and salt-out temperatures for different concentrations of NaCl and
glycerol
Parameters
NaCl
(m/v)
Freezing
Salt-out
0%
Freezing
Salt-out
10%
Freezing
Salt-out
20%
Freezing
Salt-out
30%
Glycerol (m/v)
0%
10%
20%
30%
0°C
-9°C
-9°C
-20°C
NO*
NO
NO
NO
-9°C
-20°C
-20°C
Below -20°C
NO
NO
NO
NO
-9°C
-20°C
Below -20°C
Below -20°C
NO
NO
NO
NO
NA**
NA
NA
NA
0°C
5°C
25°C
25°C
* NO denotes ‘Not observed’
** NA denotes ‘Not Applicable’. These samples were not subjected to freezing point monitoring because
they precipitated above 0°C and had no perspectives in development of anti-freeze solution
Figure 4.1.Dissolved solution (left); ice crystal (middle) and salt-out (right)
34
From the above observation, increasing either NaCl or glycerol concentrations depresses
the freezing temperature of the mixtures relative to water. With 30% glycerol, the system reaches
freezing points below -20°C at 10% NaCl, which indicates that the effective concentration of
NaCl can be reduced with the presence of glycerol. However, glycerol reduces the saturation
level of NaCl below 30%. The same result was also indicated in the research for the influence of
the addition of glycerol to salt solutions on the crystallization process (Shepard, 1976). Therefore,
the concentration of NaCl should not exceed 20% when mixed with glycerol.
4.2
Freezing and salt-out temperature for KCl and glycerol
Table 4.2 shows the saturation and freezing temperatures for KCl-glycerol solutions. 30%
KCl, regardless the concentration of glycerol, and 20% KCl-30% glycerol solution precipitated
at 25°C. When the temperature dropped to -8°C, the solution of 20% KCl-20% glycerol also
precipitated.
Table 4.2.Freezing and salt-out temperatures for different concentrations of KCl and
glycerol
Parameters
Freezing
Salt-out
Freezing
Salt-out
Freezing
Salt-out
Freezing
Salt-out
KCl
(m/v)
0%
10%
20%
30%
Glycerol (m/v)
0%
10%
20%
30%
0°C
-9°C
-9°C
-20°C
NO*
NO
NO
NO
-9°C
-20°C
-20°C
Below -20°C
NO
NO
NO
NO
-20°C
-20°C
NA
NA
NO**
NO
-8°C
25°C
NA
NA
NA
NA
25°C
25°C
25°C
25°C
* NO denotes ‘Not observed’
35
** NA denotes ‘Not Applicable’. These samples were not subjected to freezing point monitoring because they
precipitated above 0°C and had no perspectives in development of anti-freeze solution
The solutions of 30% glycerol, 10% KCl -10% glycerol, 10% KCl -20% glycerol, 20%
KCl, 20% KCl -10% glycerol and 20% KCl -20% glycerol froze at -20°C. Only 10% KCl-30%
glycerol solution can be used at -20°C, for the freezing point was lower than -20°C.
Increasing either KCl or glycerol concentrations depressed the freezing point of mixed
solutions. The trends were similar to those observed for NaCl. However, the saturation
concentration of KCl is below that of NaCl: the precipitation of KCl was observed at the
concentration of 20%, while the precipitation concentration of NaCl is 30%. Increasing the
concentration of glycerol increases the precipitation temperature of 20% KCl from -8°C to 25°C.
Therefore, it is necessary that the concentration of KCl does not exceed 10%.
4.3
Minimization of anti-freeze agent concentration
The main goal of this section is to investigate the possibility of mixing different anti-freeze
agents (in the present case, two salts and glycerol) to minimize the overall concentration of
components, but still provide desired freezing point depression. Thus, the following experiment
was conducted to identify the minimum concentrations of salts and glycerol required to achieve
freezing points below -20°C.
Based on the above experiments, the solutions containing 10% KCl, 10% or 20% NaCl,
and 10%, 20% or 30% glycerol gave promising results in the development of anti-freeze solution.
At this stage, all three components at the abovementioned concentrations were mixed to figure
out combinatorial effects of these agents and their minimum acceptable concentrations (Table
4.3).
36
Table 4.3.Freezing and salt-out temperatures for KCl - NaCl - glycerol solutions
Concentrations of agents (m/v)
Phenomenon
KCl
NaCl
Glycerol
Freezing
Salt-out
10%
10%
10%
-20°C
NO*
10%
10%
20%
-20°C
NO
10%
10%
30%
Below -20°C
NO
10%
20%
10%
Below -20°C
NO
10%
20%
20%
Below -20°C
NO
10%
20%
30%
NA**
25°C
* NO denotes ‘Not observed’
** NA denotes ‘Not Applicable’. These samples were not objected to freezing point monitoring because
they precipitated above 0°C and had no perspectives in development of anti-freeze solution
In the initial test, 30% NaCl - 0% glycerol and 30% KCl - 0% glycerol solutions
precipitated at 25°C. However, for the three-component mixture 10% KCl - 20% NaCl - 10%
glycerol and 10% KCl - 20% NaCl - 20% glycerol, the total salt concentration was 30% but no
precipitation was observed. This phenomenon indicated that the mixing of salts enhanced the
saturation level of solutions. Contrarily, increasing glycerol concentration reduced the solution
saturation level. After adding 30% glycerol, 10% KCl - 20% NaCl solution precipitated at 25°C.
The possible mechanism was that, in the presence of 30% glycerol, there were not enough water
molecules that expose negative side of dipole to attract the Na+ and K+ ions for bonding, the
cationic concentration was over the solubility threshold and the salt precipitated.
The solutions of 10% KCl -10% NaCl -30% glycerol remained unfrozen at -20°C. Thus, in
the presence of glycerol, concentrations of NaCl and KCl required to prevent freezing of the
solution can be reduced to 10% each, which allows overcoming undesired salt precipitation and
reduce the negative impact on the environment. However, the total concentration of salts
37
increases to 20%, which level is an environmental concern. Therefore, the next set of
experiments was performed to reduce salt and glycerol concentration in the anti-freeze solution.
The concentrations of NaCl and KCl were reduced to 7.5% and 5%; glycerol level was reduced
to 25% (average level between ineffective 20 % and effective 30 %). The results are presented in
Table 4.4.
Table 4.4.Freezing and salt-out temperatures for reduced concentrations of the components
Concentrations of agent (m/v)
Phenomenon
KCl
NaCl
Glycerol
Freezing
Precipitate
5%
5%
25%
-20°C
NO*
5%
5%
30%
Below -20°C
NO
5%
10%
25%
-20°C
NO
5%
10%
30%
Below -20°C
NO
10%
5%
25%
-20°C
NO
10%
5%
30%
Below -20°C
NO
7.5%
7.5%
25%
-20°C
NO
7.5%
7.5%
30%
Below -20°C
NO
7.5%
10%
25%
Below -20°C
NO
7.5%
10%
30%
Below -20°C
NO
10%
7.5%
25%
-20°C
NO
10%
7.5%
30%
Below -20°C
NO
* NO denotes ‘Not Observed’
The mixing of salts slightly increased the freezing point: the freezing point of 20% NaCl20% glycerol solution was below -20°C, while the freezing point of the mixed 10% NaCl- 10%
KCl- 20% glycerol was equal to -20°C, due to the lower anti-freeze ability of KCl. However, it is
still desirable to design anti-freeze agents from mixed solutions because: i) the total
concentration of salts can be decreased to a relatively low level, which helps to reduce the impact
38
of salts on the arctic ecosystem; ii) the desired freezing point can be obtained with the assistance
of glycerol, which is comparable to the anti-freezing ability of the pure brine (below -20°C) ; iii)
with the presence of KCl, the inhibitive ability (in respect to swelling of the reactive shale) of
drilling fluid will be enhanced significantly (Andrey, 2011).
The 25 % glycerol solution was able to prevent ice formation and salt-out when KCl was
reduced to 7.5% while keeping NaCl at 10%. The addition of 30 % glycerol allowed reducing
salt concentrations to 5% each. Thus, in the presence of glycerol, it is possible to design low-salt
anti-freeze solution. This gives a great flexibility in drilling fluid composition for drilling
permafrost. If environmental considerations are a priority, low-salt fluid can be used. However,
salts concentrations can be increased if required by the drilling conditions (e.g., shale inhibition
or drilling salt formation). Low salt concentration in anti-freeze solution also has an advantage of
better compatibility with other drilling fluid components (e.g., bentonite and polymers). For
example, in the drilling operations in 15 Mackenzie Delta wells, polyacrylamide/potassiumchloride mud has been used in drilling shale sections. In these operations, the KCl content was
maintained from 28.5 g/L to 997.5 g/L depending on the shale being drilled (Clark, 1976). From
the experimental result of the present study, the content of 5% KCl anti-freeze agent is 50 g/L,
which is within the range covered in the present work for KCl content for practical operation.
39
CHAPTER 5: RHEOLOGY OF ANTI-FREEZE POLYMER SYSTEM
Polymer solutions investigated as Arctic drilling fluids are desired to be non-solid muds
(as discussed in Chapter 2). The formulated polymer systems are expected to have good shear
thinning behavior, and generate desirable viscosity and yield point to provide efficient hole
cleaning and drilling hydraulics under low temperature environment.
The polymers such as xanthan gum, guar gum, low viscosity modified polyanionic
cellulose (MF PAC-LV), modified starch and methylcellulose (M0262, M0387, and M4170)
were selected to make the aqueous solution. For each polymer, concentrations typically used in
drilling fluid were investigated for preparing the test solution. The rheological properties of
polymer at different temperature points were tested, the influence of anti-freeze agent on the
rheological performance of polymer were investigated. The tables of test result for all the
experiments in this chapter can be found in Appendix A.
5.1
Experiment for optimum concentration of polymer solutions
Most of the water-based muds behave as plastic fluids, which is normally described by the
Bingham plastic model because of the presence of clay or polymers dispersed/ dissolved in the
base. The statistical analyses of the rheological properties of drilling muds collected from the
literature showed that the drilling fluid yield point is generally lower than 35 lb/100ft2 (16.76 Pa;
Mohammed, 2013). In drilling engineering, it is common to use a shear-thinning mud, which
provides sufficient gel to suspend cuttings when circulation is ceased but which breaks up
promptly to a thin drilling fluid when the circulation is restarted. This type of drilling fluid will
have a high ratio of yield point and plastic viscosity (YP/PV ratio; Caenn, 2011). It is desirable
to maintain the lowest possible PV at the surface, keeping the YP no higher than required to
40
provide adequate carrying capacity (Roscoe Moss Company, 2008). The YP/PV ratio is also
commonly used to indicate and characterize the plug flow (flat flow profile in the center), which
is required for cutting carrying. Higher YP/PV ratio provides flatter flow profile and hence better
hole cleaning. Usually it is appropriate to maintain the YP/PV ratio in the range of
0.7~1lb/100ft2∙cp (0.36 ~ 0.48 Pa/mPa·s; Cai, 2007). For a safe and efficient drilling operation,
the YP of each polymer should be no more than 35 lb/100ft2 and YP/PV ratio should be within
0.7~1 lb/100ft2∙cp. In the following experiments, the PV and YP of polymer solutions at different
concentrations were tested at 25°C to 0°C. The concentration of each polymer that provides
rheological parameters meeting the above criteria is considered as the optimum concentration.
5.1.1
Viscosity and yield point of xanthan gum solution as a function of concentration
and temperature
The concentration of xanthan gum solution in test was 0.2%, 0.3%, 0.6%, 1% and 1.2%
(Figure 5.1). All solutions started to freeze at 0°C. Generally the PV and YP of polymer solution
increased with the decrease of temperature, but increasing polymer concentration. When the
concentration was below 0.3%, the rheological properties were insensitive to temperature. When
the concentration increased to 0.6 – 1.0 %, both plastic viscosity and yield point are slightly
reduced when temperature increased. 1.2% xanthan gum provided significantly higher viscosity
and yield point which sharply decreased with increasing temperature.
For 0.2% xanthan gum solution, the PV increases from 11 cp (11 mPa·s) at 25°C to 14
cp (14 mPa·s) at 0°C. The YP increases from 7 lb/100ft2 (3.35 Pa) at 25°C to 14 lb/100ft2 (6.7 Pa)
at 0°C. The YP/PV ratio has increased from 0.63 lb/100ft2∙cp (0.32 Pa/mPa·s) to 1.25
lb/100ft2∙cp (0.64 Pa/mPa·s), which is very close to the criteria range 0.7~1 lb/100ft2∙cp
41
(0.36~0.48 Pa/mPa·s; Table 5.1). The PV of 0.3% xanthan gum solution increases from 10 cp at
25°C to 11 cp at 0°C. The YP increases from 15 lb/100ft2 (7.18Pa) at 25°C to 20 lb/100ft2 (9.6
Pa) at 0°C. The YP/PV ratio of 0.3% was between 1.364 and 1.82 lb/100ft2∙cp (0.66 – 0.99
Pa/mPa·s). For the xanthan gum solutions of 0.6%, 1% and 1.2%, their rheological properties
change dramatically. The YPs were all higher than 30 lb/100ft2 (14.36Pa), and their YP/PV ratios
were higher than 1.50 lb/100ft2∙cp (0.77 Pa/mPa·s), which is too high for the drilling fluid. From
the above discussion, 0.2% was selected as the optimum concentration because its YP was lower
than 35 lb/100ft2 and YP/PV ratio was the closest to the range of 0.7~1 lb/100ft2∙cp.
0.2% xanthan gum
0.6% xanthan gum
1.2% xanthan gum
80
0.3% xanthan gum
1.0% xanthan gum
40
0
180
Yield point, lb/100ft2
Plastic Viscosity,
120
0.2% xanthan gum
0.6% xanthan gum
1.2% xanthan gum
120
0.3% xanthan gum
1.0% xanthan gum
60
0
0
5
10
15
20
25
0
Temperature, ℃
5
10
15
20
25
Temperature, ℃
Figure 5.1.Test results of plastic viscosities and yield points of xanthan gum solutions
Table 5.1.YP/PV ratio of xanthan gum solutions
Temperature
0.2%(m/v)
0.3%(m/v)
0.6%(m/v)
1%(m/v)
1.2%(m/v)
23 °C
0.63
1.50
3.10
2.00
2.63
10 °C
1.08
1.36
2.25
1.81
2.02
5 °C
1.00
1.80
1.96
1.78
2.27
0 °C
1.25
1.82
2.04
1.93
1.94
42
30
5.1.2
Viscosity and yield point of guar gum solution as a function of concentration and
temperature
The concentration of the guar gum solution in test was 0.3%, 0.5%, 0.9% and 1.3%. The
solutions froze at temperatures below 0°C. Figure 5.2 shows the results of plastic viscosity and
yield point of guar gum solutions.
120
180
0.50%
0.90%
1.30%
0.30%
90
0.50%
0.90%
1.30%
150
Yield point, lb/100ft2
Plastic viscosity, cp
0.30%
120
60
30
0
0
5
10
15
20
25
30
Temperature,°C
90
60
30
0
0
5
10
15
20
25
30
Temperature,°C
Figure 5.2.Test results of plastic viscosities and yield points of guar gum solutions
Table 5.2.YP/PV ratio of guar gum solutions
Temperature
0.3% (m/v)
0.5% (m/v)
0.9% (m/v)
1.3% (m/v)
25°C
0.14
0.67
3.00
4.69
15°C
0.90
1.93
3.35
3.14
10°C
1.10
1.75
3.60
3.06
5°C
1.00
1.71
3.54
3.10
0°C
1.18
1.67
3.48
3.14
Comparing with other concentrations, 0.3% of guar gum solution has the lowest PV and
YP above 0°C, while the YP/PV ratio of 0.3% guar gum was ranging from 0.90 to 1.18
43
lb/100ft2∙cp (0.46 ~ 0.61 Pa/mPa·s; Table 5.2), which is efficient for carrying the drill cuttings in
laminar flow. The rest of the guar gum solutions all had high yield points. Under low
temperature environments, the high yield point could increase and lead to excessive pump
pressure when starting mud circulation.
5.1.3
Viscosity and yield point of modified starch solution as a function of concentration
and temperature
The concentration of modified starch solution in test was 1%, 1.5% and 2%. The
solutions froze at temperature below 0°C. Figure 5.3 shows the results of rheology test of
modified starch solutions. Increasing concentration or decreasing temperature increases PV and
YP.
120
80
1.50%
1%
2%
Yield point, lb/100ft2
Plastic viscosity, cp
1%
90
60
30
0
1.50%
2%
60
40
20
0
0
10
20
Temperature,°C
30
0
5
10
15
20
25
30
Temperature,°C
Figure 5.3.Test results of plastic viscosities and yield points of modified starch solutions
Comparing with xanthan gum and guar gum solution, the PV and YP of modified starch
solution was much lower. For example, at 0°C, the YP of 1% modified starch solution was 16
lb/100ft2 (7.6 Pa) which is much lower than the YP of 0.9% guar gum and YP of 1% xanthan
gum, 94 lb/100ft2 (45 Pa) and 54 lb/100ft2 (25.86 Pa) respectively. The YP/PV ratio of three
44
modified starch solutions were close to each other and all stayed between 0.65 and 0.85
lb/100ft2∙cp (0.33 ~ 0.44 Pa/mPa·s; Table 5.3), which was also lower than xanthan gum and guar
gum solutions. Since we expect the increase of PV and YP below 0°C, 1% modified starch
solution was better than the other two solutions, for the PV of the other two solutions was too
high.
Table 5.3.YP/PV ratio of modified starch solutions
Temperature
1.0% (m/v)
1.5% (m/v)
2.0% (m/v)
23°C
0.80
0.70
0.72
15°C
0.71
0.74
0.70
10°C
0.68
0.76
0.73
5°C
0.67
0.81
0.72
5°C
0.73
0.77
0.69
5.1.4
Viscosity and yield point of methylcellulose solution as a function of concentration
and temperature
Three commercial products of methylcellulose, M7140, M0262 and M0387, with
different molecular weight were selected for testing. The solutions froze at temperatures below
0°C. M7140 has the lowest molecular weight, so the concentration of M7140 solution needs to
be relatively high to provide proper viscosity control. The solution generated reasonable yield
point, but the plastic viscosities are extremely high (Figure 5.4). At 0°C, the YP of 2.4% M7140
solution was 10 lb/100ft2 (4.79 Pa), which was a low value for drilling fluid, while the PV was
43cp. Consequently, the YP/PV ratio was as low as 0.23 lb/100ft2∙cp (0.12 Pa/mPa·s), which was
not practical for holding chips during drilling operation.
45
120
80
3%
3.60%
2.40%
Yield point, lb/100ft2
Plastic viscosity, cp
3.60%
90
60
30
0
3%
2.40%
60
40
20
0
0
5
10
15
20
25
30
0
5
Temperature,°C
10
15
20
25
30
Temperature,°C
Figure 5.4.Plastic viscosities and yield points of M7140 methylcellulose solutions
Table 5.4.YP/PV ratio of M7140 methylcellulose solutions
Temperature
2.4% (m/v)
3.0% (m/v)
3.6% (m/v)
23 °C
0.10
0.14
0.12
15 °C
0.18
0.19
0.11
10 °C
0.23
0.25
0.09
5 °C
0.22
0.21
0.07
0 °C
0.23
0.23
0.10
Methylcellulose M0262 has higher molecular weight in comparing with M7140. The
plastic viscosity and yield point were affected by concentration remarkably (Figure 5.5). At 0°C,
the PV of 1.2% M0262 was 91cp (91 mPa∙s), which is much greater than the PV of 1% M0262
solution, 52cp (52 mPa∙s). The YP/PV ratios for both concentrations were generally lower than
0.5 lb/100ft2∙cp (0.26 Pa/mPa·s, Table 5.4). So M0262 was not an option for viscosity control.
46
80
120
1.20%
1%
Yield point, lb/100ft2
Plastic viscosity, cp
1%
1.20%
60
90
40
60
30
20
0
0
0
5
10
15
20
Temperature,°C
25
30
0
10
20
Temperature,°C
30
Figure 5.5.Plastic viscosity and yield point of M0262 methylcellulose solutions
Table 5.5.YP/PV ratio of M0262 methylcellulose solutions
Temperature
1.0% (m/v)
1.2% (m/v)
23°C
0.26
0.33
15°C
0.33
0.42
10°C
0.33
0.49
5°C
0.38
0.49
0°C
0.44
0.55
The concentration of the M0387 solution in test was 0.6%, 0.8% and 1%. Due to the high
molecular weight, M0387 has higher rheology (Figure 5.6). The PV and YP were all greater than
the other two methylcelluloses. Decreasing the concentration of M0387 decreases the YP/PV
ratio. The 1% and 0.8% M0387 solution had higher YP/PV ratio than 0.6% M0387 solution
(Table 5.6), but the problem was that their YP and PV were much higher than the normal range
of drilling fluid viscosity, while 0.6% M0387 has relatively low PV and YP. From this
perspective, 0.6% M0387 was better than 0.8% and 1% M0387. If decreasing the concentration
of M0387, the YP and PV will decreases but the YP/PV ratio will become lower than 0.6%
M0387’s. Therefore 0.6% is the optimum concentration of M0387.
47
80
1%
0.80%
1%
0.60%
Yield point, lb/100ft2
Plastic viscosity, cp
120
90
60
30
0
0.80%
0.60%
60
40
20
0
0
5
10
15
20
25
30
Temperature,°C
0
10
20
Temperature,°C
30
Figure 5.6.Plastic viscosities and yield point of M0387 methylcellulose solutions
Table 5.6.YP/PV ratio of M0387 methylcellulose solutions
Temperature
0.6% (m/v)
0.8% (m/v)
1.0% (m/v)
23 °C
0.19
0.47
0.58
15 °C
0.31
0.59
0.67
10 °C
0.45
0.53
0.88
5 °C
0.47
0.70
0.92
0 °C
0.56
0.84
0.91
5.1.5
Viscosity and yield point of MF PAC-LV as a function of concentration and
temperature
The concentration of the MF PAC-LV solution in test was 1.0% and 1.2% (Figure 5.7).
The solutions froze at temperatures below 0°C. Compared with the other polymer solutions at the
same concentration, the YP of MF PAC-LV was relatively low. Besides, the YP/PV ratio of the
two MF PAC-LV solutions was between 0.25 and 0.85 lb/100ft2∙cp (0.13 ~ 0.44 Pa/mPa·s; Table
5.7), which were also too low to provide the flat flow profile. However, we could still expect the
YP of MF PAC-LV solution will increase and provide acceptable rheology under low
48
temperature conditions. We selected 1% as the optimum concentration of MF PAC-LV, for its
PV and YP were lower than the one of 1.2% MF PAC-LV’s.
80
1%
1%
1.20%
Yield point, lb/100ft2
Plastic viscosity, cp
120
90
60
30
0
0
10
20
1.20%
60
40
20
0
30
0
Temperature,°C
10
20
30
Temperature,°C
Figure 5.7.Plastic viscosity and yield point of MF PAC LV solutions
Table 5.7.YP/PV ratio of MF PAC LV solutions
5.1.6
Temperature
1.0% (m/v)
1.2% (m/v)
25°C
0.27
0.43
15°C
0.41
0.49
10°C
0.62
0.63
5°C
0.56
0.71
0°C
0.60
0.80
Analysis of rheology performance of polymer solutions at different concentrations
From the above test results, the plastic viscosity and yield point of the seven polymer
solutions universally increased with increasing concentration or decreasing temperature, but the
temperature sensitivity of polymers was different. Comparing with the other polymers, the
plastic viscosity of the two methylcellulose products M4170 and M0262 has the most significant
increase with the decrease of temperature. Consequently the YP/PV ratio of both polymer
49
solutions was much lower than 0.7 lb/100ft2∙cp (0.38 Pa/mPa·s), which was not acceptable for
carrying drill cuttings. Therefore both of them were not suitable in the anti-freeze drilling fluid.
The rheology of polymers in the category of natural gums was better than the polymers
in the category of cellulose. Under the condition of same concentration or temperature, the PV
and YP of natural gum were generally lower than that of celluloses’, and the YP/PV ratio of
natural gum was much closer to the range of 0.7~1 lb/100ft2∙cp (Cai, 2007). We can conclude
that the natural gum polymer is more desirable to be used in the non-solid polymer drilling fluid
as viscosifier.
This study has tested the rheology of polymer solutions in different concentration and
different temperature condition, and selected the optimal concentration that provided the best
rheology control (Table 5.8). In next set of experiment, the polymer solution in optimal
concentration will be mixed with anti-freeze agent, to test the rheology under different
temperature conditions, including the temperature below 0°C.
Table 5.8.Optimum concentration of selected polymer
Polymer
Xanthan gum
Guar gum
Modified
starch
Methylcellulose
M0387
MF PACLV
Concentration
(m/v)
0.2%
0.3%
1%
0.6%
0.5%
5.2
Rheology of polymers in response to anti-freeze base
For the polymer solutions with optimized concentration (from above experiments), their
rheological behavior under sub-freezing temperature needs to be tested. The compatibility of
polymer with anti-freeze agent is another issue that needs to be considered for designing the
50
drilling fluid. In the following experiments, the optimized polymer solutions were mixed with
one of the three formulas of anti-freeze agent (5%NaCl + 5%KCl + 30%glycerol, 10%NaCl+
7.5%KCl+ 25%glycerol, 10%KCl + 10%NaCl + 30%glycerol) respectively. The mixed solutions
were labeled as AFS1, AFS2 and AFS3 and prepared at temperature points ranging from 25°C to
-20°C. The salt precipitation and ice formation was monitored. The rheological parameters
(apparent viscosity, plastic viscosity and yield point) of the mixed solution under different
temperature were also measured.
5.2.1
Viscosity and yield point of 0.2% xanthan gum solution as a function of salinity and
temperature
In 0.2% xanthan gum solution, adding salts decreased the apparent viscosity (AV) of the
polymer solution (Table 5.9). At the same shear rate, the AV of AFS1 and AFS 2 were lower
than the AV of 0.2% xanthan gum solution.
Table 5.9.Apparent viscosity of 0.2% (m/v) xanthan gum in response to anti-freeze agents
at 0°C
Shear rate, s-1
1022
511
340.7
170.3
10.22
Polymer
21.0
30.0
34.5
45.0
250.0
5.11
300.0
Apparent viscosity, cp
AFS1
AFS2
13.0
14.5
14.0
16.0
13.5
15.0
12.0
15.0
50.0
50.0
AFS3
30.5
35.0
42.0
48.0
150.0
100.0
200.0
100.0
The PV has changed slightly, for the PV of 0.2% xanthan gum was very close to the PV
of AFS1 and AFS3 (Figure5.8). The YP of 0.2% xanthan gum has decreased significantly after
51
adding the salts. We can also notice that the AV and PV of AFS3 were higher than the other
three solutions. This can be explained by the assumption that with the presence of excess salts,
the solubility of xanthan gum was affected. The un-dissolved xanthan gum formed large-size
particles, which increased the inner friction in the fluid, hence increased the apparent viscosity.
However, the monovalent salts break up the inner structure formed by polymer particles, that’s
why the yield point of all polymer solutions has decreased. The PV and YP of all polymer
solutions increase with the decrease of temperature. Especially the PV and YP have increased
sharply when the temperature is below 0°C.
100
40
AFS1
AFS2
AFS3
Polymer
Yield point, lb/100ft2
Plastic Viscosity, cp
Polymer
80
AFS1
AFS2
AFS3
30
60
20
40
10
20
0
0
-30
-20
-10
0
10
20
30
Temperature, ℃
-30
-10
10
30
Temperature, ℃
Figure 5.8.Plastic viscosity and yield point of anti-freeze xanthan solutions
5.2.2
Viscosity and yield point of 0.3% guar gum solution as a function of salinity and
temperature
Adding salts in anti-freeze agent increased the apparent viscosity of 0.3% guar gum
(Table 5.10). The PV and YP have also enhanced with the increase of salts concentration in antifreeze agent (Figure 5.9). Aside from the effect of salts, the rheological parameters of 0.3% guar
gum were also increased with decreasing temperature, especially below -10°C, the PV and YP of
52
polymer solutions has increased sharply. The YP of AFS1 at -20°C was 32 lb/100ft2 (15.3Pa),
which was lower than the YP of AFS2 and AFS3. The PV of AFS1 was also lower than the PV
of the other two mixed solutions. These results indicated that AFS1 was more reliable than others
for chip suspension under different temperature conditions. The YP of AFS2 at -20°C was 37
lb/100ft2 (17.7 Pa), which is a little bit higher than the criteria. However, the YP/PV ratio of
AFS2 was within 0.7 ~ 1 lb/100ft2∙cp (0.36 ~ 0.48Pa/mPa·s; Table 5.11), so it is still practical to
apply AFS2 into the drilling fluid if the drilling condition requires higher salt concentration.
Table 5.10.Apparent viscosity of 0.3% (m/v) guar gum in response to anti-freeze agents at
0°C
Shear rate, s-1
Apparent viscosity, cp
AFS1
AFS2
32.5
38.5
41.0
50.0
46.5
58.5
60.0
78.0
150.0
250.0
200.0
300.0
Polymer
18.0
24.0
30.0
45.0
100.0
150.0
1022
511
340.7
170.3
10.22
5.11
60
120
Polymer
AFS1
AFS2
AFS3
100
Yield point, lb/100ft2
Plastic viscosity, cp
AFS3
48.5
62.0
72.0
93.0
300.0
400.0
80
60
40
20
0
Polymer
50
AFS1
AFS2
AFS3
40
30
20
10
0
-30
-20
-10
0
10
Temperature, ℃
20
30
-30
-20
-10
0
10
Temperature, ℃
Figure 5.9.Plastic viscosity and yield point of anti-freeze guar gum solutions
53
20
30
Table 5.11.YP/PV ratio of 0.3% (m/v) guar gum in response to anti-freeze agents
Temperature
25 °C
10 °C
5 °C
0 °C
-10 °C
-20 °C
5.2.3
YP/PV, lb/100ft2∙cp
AFS1
AFS2
0.53
0.94
NA
NA
NA
NA
0.71
0.85
0.64
0.79
0.82
0.76
Polymer
0.07
0.56
0.51
0.51
Frozen
AFS3
0.95
0.77
NA
0.77
0.62
0.50
Viscosity and yield point of 1% modified starch solution as a function of salinity
and temperature
The apparent viscosity of 1% modified starch solution was affected significantly by the
concentration of salt. Increasing salts concentration increased the AV (Table 5.12).
Table 5.12.Apparent viscosity of 1% (m/v) modified starch in response to anti-freeze agents
at 0°C
Shear rate, s-1
1022
511
340.7
170.3
10.22
5.11
Polymer
21.0
24.0
25.5
27.0
50.0
100.0
Apparent viscosity, cp
AFS1
AFS2
22.5
25.0
25.0
27.0
25.5
28.5
27.0
30.0
50.0
50.0
100.0
100.0
AFS3
31.5
35.0
37.5
39.0
50.0
100.0
Among the four solutions, AFS3 has the highest PV, while the PV of AFS2 was lower
than AFS3 but higher than AFS1 (Figure 5.10). This result indicated that the PV of mixed
solution has increased with increasing of salt concentration. The YP of mixed solutions has also
54
changed the same way. Meanwhile, temperature has a great impact on the PV of mixed solutions.
Above 0°C, the YP of mixed solutions have not changed too much from the 1% Modified starch
solutions, but as the temperature has dropped below 0°C, the YP of mixed solutions has
increased sharply.
40
100
AFS1
AFS2
Polymer
AFS3
Yield point, lb/100ft2
Plastic viscosity, cp
Polymer
80
60
40
20
0
AFS1
AFS2
AFS3
30
20
10
0
-30
-20
-10
0
10
20
30
Temperature, ℃
-30
-20
-10
0
10
20
30
Temperature, ℃
Figure 5.10.Plastic viscosity and yield point of anti-freeze modified starch solutions
5.2.4
Viscosity and yield point of 0.5% MF PAC-LV solution as a function of salinity and
temperature
With the presence of salts, the AV of 0.5% MF PAC-LV solution was decreased (Table
5.13). The AV of the three mixed solutions was all lower than the AV of 0.5% MF PAC-LV
solution.
Above 0°C, the PV of AFS1, AFS2, AFS3 and 0.5% MF PAC-LV did not have
significant difference, which means the salinity has slight effect on the PV, but below 0°C, the
PV of mixed solutions has increased sharply (Figure 5.11). On the contrary, the YP of the mixed
solutions was generally lower than the YP of polymer solution. The decrease of temperature
gently increased the YP of mixed solution.
55
Table 5.13.Apparent viscosity of 0.5% (m/v) MF PAC-LV in response to anti-freeze
agents
Shear rate, s-1
Apparent viscosity, cp
AFS1
AFS2
25.0
27.5
28.0
31.0
28.5
30.0
30.0
33.0
50.0
75.0
100.0
100.0
Polymer
32.0
38.0
42.0
51.0
150.0
200.0
1022
511
340.7
170.3
10.22
5.11
100
AFS1
AFS2
AFS3
80
60
40
20
0
Yield point, lb/100ft2
40
Polymer
Plastic viscosity, cp
AFS3
32.0
36.0
36.0
39.0
100.0
150.0
Polymer
AFS1
AFS2
AFS3
30
20
10
0
-30
-20
-10
0
10
20
30
-30
-20
-10
0
10
20
Temperature, ℃
Temperature, ℃
Figure 5.11.Plastic viscosity and yield point of anti-freeze MF PAC-LV solutions
5.2.5
Viscosity and yield point of 0.6% MC M0387 solution as a function of salinity and
temperature
After adding salts, the rheological parameters of 0.6% methylcellulose have decreased
sharply. The AV, PV and YP have been reduced with the increase of salts concentration (Table
5.14 and Figure 5.12).
56
30
Table 5.14.Apparent viscosity of 0.6% MC M0387 in response to anti-freeze agents
Shear rate, s-1
Apparent viscosity, cp
AFS1
AFS2
19.5
16.5
22.0
18.0
25.5
16.5
27.0
18.0
50.0
50.0
100.0
100.0
Polymer
46.0
56.0
61.5
72.0
75.0
100.0
1022
511
340.7
170.3
10.22
5.11
40
80
AFS1
AFS2
Polymer
AFS3
Yield point, lb/100ft2
Polymer
Plastic viscosity, cp
AFS3
13.0
14.0
15.0
15.0
50.0
100.0
60
40
20
AFS1
AFS2
AFS3
30
20
10
0
0
-30
-20
-10
0
10
Temperature, ℃
20
30
-30
-20
-10
0
10
20
Temperature, ℃
Figure 5.12. Plastic viscosity and yield point of anti-freeze 0.6% MC M0387 solutions
Above 0°C, the PV of 0.6% methylcellulose solutions has decreased a lot after adding antifreeze agent. The PV of mixed solutions was very close to each other. When the temperature was
suppressed below 0°C, the PV of mixed solutions has been divided and increased distinctly. The
YP of 0.6% methylcellulose has also decreased with increasing salts.
5.2.6
Analysis of the response of polymer solution to anti-freeze agent
57
30
In the experiments of the polymer solutions with three combinations of anti-freeze
agents, there was no precipitation or ice formation.
The presence of anti-freeze agent decreased the viscosity of 0.2% xanthan gum solution
compared to that of xanthan gum in water alone. The possible mechanism is that with the
presence of salt, charge screening causes the side chains of xanthan gum molecule to collapse
down to the main chain. The polymer molecule formed a rod-like shape and decreased the
viscosity (Hemmatzadeh et al, 2011).
The test result of 0.5% MF PAC-LV and 0.6 % MC 0387 showed the similar response of
rheology to the presence of salt; like xanthan gum --- adding salts decreases the viscosity. But
the mechanism of response to salt is different from xanthan gum. When MF PAC-LV is
dissolved in water, the cations release from the polymer chain, which make the polymer anionic
and free in water. When the polymer is hydrated in water, the viscosity increases as the size of
the envelope surrounded the polymer increases. After adding salt, the availability of water is
limited and polymer cannot hydrate and expand easily. It means that the hydrogen bonding is not
formed between water molecules and the polymer chains. Therefore the viscosity of this fluid
will be highly depressed (Alaskari and Teymoori, 2007).
In contrast, results of the test showed that the viscosity of the 0.3% guar gum solution
markedly increased when the salts were added. This suggests that the inter-molecular networks
of guar gum and water were not disturbed. The possible mechanism to explain the result is that
adding salts can facilitate the formation of intermolecular aggregates due to the alteration of the
charge density and conformation of guar gum (Gittings et al, 2001).
58
For 1% modified starch, a slight increase in apparent viscosity was observed with
addition of salts. This might be explained as that the swelling of the starch granules are restricted
by both the electrostatic interaction between starch and ions from NaCl and the competition
between the salts and starch for available water molecules (Samutsri and Suphantharika, 2012).
Similar results were observed for the effect of the NaCl on the physicochemical properties of
potato starch (Chen et al, 2014).
According to the rheology test results, with increasing shear rate, the apparent viscosity
of all the solutions has decreased, which indicated good shear thinning characteristics. Among
these polymers, the AV of guar gum solutions has the most significant decrease with the increase
of shear rates, besides, the YP/PV ratio of 0.3% guar gum solutions were generally higher than
the ratio of other mixed polymer solutions, thus the guar gum solution was selected as the base
fluid of the anti-freeze non-solid drilling fluid system. For each type of polymer, combining with
5% NaCl + 5% KCl + 30% glycerol generated the lowest effect on the rheological properties
than the other two anti-freeze formulations. Therefore, in common permafrost drilling operation,
the low salt anti-freeze agent 5% NaCl + 5% KCl + 30% glycerol is good enough to corporate
with guar gum systems for viscosity control. If the drilling condition requires high salt
concentrations, NaCl and KCl should be discreetly added, up to 10% and 7.5% respectively.
59
CHAPTER 6: RHEOLOGICAL MODELS AND HYDRAULICS ESTIMATION OF
ANTI-FREEZE POLYMER SYSTEMS
6.1
Rheological model optimization
The rheological properties of drilling fluids describe the characteristics of the deformation
and flow of the drilling fluid under the effect of an imposed force. Rheological properties are
often described by the rheogram as depicted in Figure 6.1. In this figure, the four basic
rheological fluid types are shown: i) Plastic fluids, which are characterized by a yield point
(YP = τ0 ) and a constant plastic viscosity (PV) relating the shear stress, τ, to the shear rate, γ; ii)
Pseudoplastic fluids for which τ0 = 0 ; iii) Newtonian fluids, for which PV is constant and τ0 =
0; iv) Dilatant fluids or shear thickening fluids.
Figure 6.1.Schematic rheogram showing rheological types (Adapted from Awele, 2014)
1-Plastic fluid; 2- Pseudoplastic fluid; 3- Newtonian fluid; 4-Dilatant fluid;
60
τ- Shear stress, lb/100ft2 or Pa; γ- Shear rate, s-1; τ0 -YP = Yield point, lb/100ft2 or Pa; PV-Plastic
viscosity, cp or mPas
The most widely used drilling fluids are plastic and pseudoplastic fluids. Aqueous
solutions of high-molecular compounds and emulsions all belong to the category of
pseudoplastic fluid, which can start to flow at an extremely low shear stress, and have no gel
strength. The viscosity decreases with the increase of shear stress. As the well goes deeper, it
becomes increasingly important to predict and control the rheology of drilling fluids and
hydraulics of the well. Rheological models to discuss the fluid properties are adopted for
prediction and calculation of the shear stress and frictional pressure losses. The most-used
rheological models are the Newtonian, Bingham and Power-law models. The limitation of
Bingham and Power Law models is that Bingham model mostly fails to predict low shear
behavior because Bingham YP is higher than the true yield stress, while Power law model is not
able to describe the rheological properties of drilling fluid under high shear rate.
Before the new API RP 13D release in 2006, API recommended to predict fluid behavior
with a two-part power law model. One part predicted the fluid behavior at low shear rates, and
another part modeled the high shear properties (Rehm et al, 2012). The Herschel-Bulkley model
is one of the new rheological models that better describe the rheological properties of drilling
fluid under a wider range of shear rate (Power, 2003). This section presents the comparison of
several major rheological models to select the best representation of the relationship between the
shear stress and shear rate for the anti-freeze polymer system. The models tested are Newtonian,
Bingham, Power-law, API dual Power-law and Herschel-Bulkley.
61
The lowest absolute average percent error (EAAP) between the measured and calculated
(predicted using the model relationship) shear stress is the criterion for selecting the model of a
given drilling fluid (Equation 6.1).
E𝐴𝐴𝑃 = [(1⁄N) ∑|(𝜏𝑚𝑒𝑎𝑠𝑢𝑟𝑒𝑑 − 𝜏𝑐𝑎𝑙𝑐𝑢𝑙𝑎𝑡𝑒𝑑 )/𝜏𝑚𝑒𝑎𝑠𝑢𝑟𝑒𝑑 |] × 100.............................................. (6.1)
Where N is the number of shearing speed.
6.1.1
Newtonian Model
The Newtonian fluid has linear relationship between shear stress (τ) and shear rate (γ).
The viscosity (μ) is constant at all shear rates under isothermal conditions. Also, there is no stress
required to initiate the flow. The equation describing a Newtonian fluid:
τ = μγ…………………………………………………………………………………………. (6.2)
Where: τ is shear stress, lb/100ft2; μ is viscosity, cp; γ is shear rate, s-1.
The dial readings of the anti-freeze system of 0.3% guar gum + 5% KCl + 5% NaCl + 30%
glycerol solution at 25°C are recorded. The data will follow through this model selection process.
The geometry of Fann viscometer determines the relationship of shear rate of rotor and its
rotational velocity (Equation 6.3). The dial reading θ is proportional to shear stress (Equation
6.4). To convert laboratory units to field engineering units (Table 6.1), we need to apply
conversion factors:
γ = 1.703N, ………………………………………………………………………………… (6.3)
τ = 1.067θ . ………………………………………………………………………………..… (6.4)
Where: γ is shear rate, s-1; θ300 is dial reading of viscometer at 300 rpm; 1 lb s/100ft2 = 478.8 cp.
62
Table 6.1.Shear stress of 0.3% guar gum anti-freeze system measured in field units
RPM
(N)
Reading
(θ)
Shear rate
(s-1)
Shear stress
(lb/100ft2)
600
38
1021.8
39.5
300
23
510.9
24.5
200
18
340.6
19.2
100
10
170.3
10.7
6
2
10.2
2.1
3
1
5.1
1.1
The shear stresses can be estimated as function of viscosity and calculated by the
following equations.
μ = θ300 ………………………………………….…………………………………………… (6.5)
τ = μγ………………………………………….………………..………………………..…… (6.6)
Where: θ300 is dial reading of viscometer at 300 rpm; 1 lb·s/100ft2 = 478.8 cp.
By using the example, for the Newtonian model, EAAP = 37.2%. Fig 6.2 shows a
comparison of measured data and fitted Newtonian model.
63
Measured shear stress
60.00
EAAP=37.2%
50.00
τ, (lb/100ft2)
y = 0.048x
40.00
30.00
μp=23 cp
20.00
10.00
0.00
0.0
200.0
400.0
600.0
800.0
1000.0
1200.0
γ, (sec-1)
Figure 6.2.Comparison between measured data and fitted Newtonian model (μ=23 cp) for
0.3% guar gum anti-freeze system
6.1.2
Bingham Plastic Model
The Bingham plastic model is a two-parameter rheological model that is widely used in
the drilling industry to describe plastic fluids. For the Bingham plastic fluids, initial stress (yield
stress) is required to initiate the flow. The model is described according to:
τ = μ𝑝 𝛾 + 𝜏0 .............................................................................................................................. (6.7)
Where, for the viscometer readings:
μ𝑝 = θ600 − θ300 ....................................................................................................................... (6.8)
τ0 = θ300 − μp ........................................................................................................................... (6.9)
Where: μ𝑝 is plastic viscosity, cp; τ0 is yield point, lb/100ft2.
64
For this example, the Bingham plastic model EAAP is 188.25%. Fig. 6.3 shows a
comparison between measured data and model.
Measured shear stress
50.0
EAAP=188.25%
τ, (lb/100ft2)
40.0
y = 0.0292x + 9
30.0
τ = μpγ + τ0
μp = 14
τ0 = 9
20.0
10.0
0.0
0.0
200.0
400.0
600.0
800.0
1000.0
1200.0
γ, (sec-1)
Figure 6.3.Comparison between measured data and fitted Bingham model for 0.3% guar
gum anti-freeze system
6.1.3
Power Law Model
Power law model is a two-parameter rheological model to describe the flow behavior of
pseudoplastic fluid. The viscosity of power law fluid decreases with increasing shear rate. No
initial stress is required to initiate the flow. Comparing with Bingham plastic model, the power
law model provides a better description for the flow behavior in low shear rate condition. The
Power law relationship is defined as:
τ = 𝑘γn ................................................................................................................................... (6.10)
Where k is the consistence index, dyne sec 𝑛 /100 𝑐𝑚2; n is flow behavior index. 1 lb/100ft2 =
478.8 dyne secn/100cm2, these are determined from the viscometer readings:
65
𝜃
n = 3.32 log (𝜃600 )………………………………………………………..………………………….. (6.11)
300
k=
510×𝜃300
511𝑛
………………………………………………………...………………………………... (6.12)
Using Eq. 6.1, EAAP = 5.94%. Fig. 6.4 shows a comparison between measured data and fitted
Power law model.
Measured shear stress
50
EAAP=5.94%
(τ, lbf/100ft2)
40
y = 0.3408x0.6855
30
τ = kγn
n = 0.6855
k = 0.3408
20
10
0
0.0
200.0
400.0
600.0
800.0
1000.0
1200.0
γ, (sec-1)
Figure 6.4.Comparison between measured data and fitted Power law model for 0.3% guar
gum anti-freeze system
6.1.4
API Model (RP 13D)
API RP 13D provides IS standard practice for drilling fluid rheology and hydraulics, and
their application to drilling operations (API, 2010). A modified Power Law model is
recommended in the API RP 13D for the calculation of frictional pressure losses. The advantage
of API power law model is it matches the shear rates from viscometer with shear rates actually
inside the drillpipe and annulus. This model uses four readings instead of two as in other models:
Inside the drillpipe, θ600 and θ300 are used for rheology and pressure loss calculations. Inside the
66
annulus, θ3 and θ100 are used for rheology and pressure loss calculations. These dual readings
allow better prediction of viscosity in low and high shear rate regions. The measured and
calculated shear stresses are shown as table 6.6. Using Eq. 6.1, EAAP = 4.14%. Fig. 6.5 shows a
comparison between measured data and model.
 Pipe Flow
𝜃
n𝑝 = 3.32 log (𝜃600 ).................................................................................................................. (6.13)
300
k𝑝 =
5.11𝜃600
1022n𝑝
dyne sec𝑛 / 𝑐𝑚2 ................................................................................................... (6.14)
 Annulus Flow
n𝑎 = 0.657 log (
k𝑎 =
5.11𝜃100
170.2n𝑎
𝜃100
𝜃3
)............................................................................................................... (6.15)
dyne sec𝑛 / 𝑐𝑚2 ................................................................................................... (6.16)
50.0
EAAP=4.14%
τ, (lb/100ft2)
40.0
y = 0.3415x0.6855
30.0
y = 0.3652x0.657
20.0
τ = kp ߛ na
na = 0.657
ka = 0.3652
10.0
np
τ = kp ߛ
np = 0.6855
kp = 0.3415
0.0
0.0
200.0
400.0
600.0
γ, (sec-1)
800.0
1000.0
1200.0
Figure 6.5.Comparison between measured data and fitted API model for 0.3% guar gum
anti-freeze system
67
6.1.5
Herschel-Bulkley Model
The Herschel-Bulkley is a three-parameter rheological model, which is described as
Power law model to accommodate the existence of a yield point. Most recently, the usage of
Herschel-Bulkley model has increased because it describe the rheological properties of drilling
fluid more accurately over a wide range of shear rate. The parameter τy is the actual yield point
of drilling fluid, which indicates the lowest shear stress that propels the fluid to flow. It is not an
extrapolated value, so it means completely different with the Bingham yield point τ0 . The value
of τy is related to the type and concentration of the polymer agents, besides the solid content also
affects it. The shear stresses can be calculated by the following equations:
τ = τy + kγn ............................................................................................................................ (6.17)
τy = 2θ3 − θ6 , lb/100f𝑡 2 ........................................................................................................ (6.18)
𝜃600 −τy
n = 3.32log(𝜃
300 −τy
K=
(𝜃300 −𝜏𝑦 )
511𝑛
)................................................................................................................ (6.19)
, dyne sec𝑛 / 𝑐𝑚2 .................................................................................................. (6.20)
Using Eq. 6.1, EAAP = 9.65%. Fig. 6.6 shows a comparison between measured data and model.
68
Measured shear stress
50.0
EAAP=9.65%
(τ, lbf/100ft2)
40.0
y = 0.32x0.6855
30.0
τ = τy+kγn
τy= 0
n = 0.6855
k = 0.32
20.0
10.0
0.0
0.0
200.0
400.0
600.0
800.0
1000.0
1200.0
γ, (sec-1)
Figure 6.6.Comparison between measured data and fitted Herschel-Bulkley model for 0.3%
guar gum anti-freeze system
6.1.6
Conclusion of rheological model selection
Since the rheological properties of drilling fluid are significantly affected by the
temperature, we need to investigate the rheological model of all the anti-freeze polymer solution
under different temperature conditions. The optimum polymer solutions (See Table.5.1) were
mixed with anti-freeze base 5% KCl + 5% NaCl + 30% glycerol. The measured dial readings are
listed in Appendix B. Table 6.2 shows the calculated EAAP of different anti-freeze polymer
solutions by different models at four temperature points.
From the results, we can conclude that the anti-freeze polymer solutions are
pseudoplastic fluids. According to Table 6.2, the API Power Law model provides the lowest
EAAP for anti-freeze polymer solution at all temperature points. Generally, the API Power law
model can better describe the flow behavior of anti-freeze polymer solution when compared with
other rheological models.
69
Table 6.2.Summary of EAAP of anti-freeze polymer solutions from different models
EAAP of Anti-freeze polymer solutions
Temperature
25°C
0°C
-10°C
-20°C
Models
Newtonian
Bingham
Power law
API
HerschelBulkley
Newtonian
Bingham
Power law
API
HerschelBulkley
Newtonian
Bingham
Power law
API
HerschelBulkley
Newtonian
Bingham
Power law
API
HerschelBulkley
0.3% Guar
gum
37.20%
188.25%
5.94%
4.14%*
0.2%
Xanthan gum
35.99%
22.28%
29.78%
9.24%
1% Modified
starch
21.40%
70.20%
19.63%
6.55%
0.5% MF
PAC-LV
22.49%
20.10%
26.22%
7.67%
0.6% MC
M0387
25.13%
164.95%
9.70%
6.08%
9.65%
54.20%
24.30%
30.73%
14.64%
30.40%
210.60%
3.37%
1.35%
22.96%
66.30%
27.60%
16.80%
20.76%
268.90%
6.98%
4.40%
22.48%
219.98%
3.98%
2.76%
28.29%
216.14%
4.08%
3.21%
14.50%
46.30%
5.16%
6.30%
9.94%
36.30%
188.70%
6.04%
5.04%
17.93%
124.74%
34.34%
6.10%
20.97%
143.55%
10.87%
4.49%
17.35%
268.47%
7.13%
2.36%
24%
500.11%
43.00%
3.20%
15.10%
18.53%
16.30%
8.73%
39.39%
39.17%
136.47%
11.72%
0.50%
14.52%
271.04%
8.18%
2.31%
19.66%
165.20%
11.70%
2.99%
12.24%
653.97%
53.00%
1.90%
27.86%
339.29%
19.31%
4.72%
6.73%
7.97%
5.74%
49.20%
18.19%
* Data in bold denotes the lowest EAAP
6.2
Hydraulics estimation
One of the principal functions of drilling fluid is transferring hydraulic power. Hydraulic
power is one of the most important hydraulic parameters impacting the rate of penetration. The
bit pressure drop decreases the bit hydraulic power. The total fluid pressure is generated by the
pump. During the procedure of transferring the pump pressure and pump hydraulic power, it is
inevitable to lose a portion of the available pressure, and then power, to friction. Drilling fluid
70
that comes from mud pump, flows through the surface equipment, drillpipe, drill collar, drill bit
and annulus. Flowing through each section meets friction and causes irreversible pressure losses.
The prediction of frictional pressure losses is important in many field operations, including
drilling, completion, fracturing, acidizing, work over and production.
6.2.1
Frictional Pressure Loss Calculation
In Section 6.1, the API power law model provided reasonably low error for all anti-
freeze polymer systems. This model will then be used to estimate the pressure loss based on the
flow regime that is to be determined by the Reynolds number (N𝑅𝑒 ) at a particular fluid flow rate,
and the friction factor, 𝑓. The equations for API Power Law model are implemented in the
pressure loss prediction according to the following calculation.
 Pipe Flow
a. Pipe velocity:
V𝑝 =
0.408𝑞
𝐷𝑝2
.................................................................................................................... (6.21)
Where 𝑞 is the flow rate, gal/min; 𝐷𝑝 is the inner diameter of drill pipe, in; V𝑝 is the pipe
velocity, ft/s
b. Reynolds number:
N𝑅𝑒 =
928𝐷𝑝 𝑉𝑝 𝜌
𝜇𝑒
; 𝜇𝑒 = 100𝑘(
96𝑉𝑝 𝑛−1 3𝑛+1 𝑛
) ( 4𝑛 ) ;
𝐷𝑝
𝜃
𝑛 = 3.32 log (𝜃600 ); 𝑘 =
300
5.1𝜃600
1022𝑛
…... (6.22)
Where 𝜇𝑒 is the equivalent viscosity, cp; 𝜌 is the mud density, lb/gal; 𝑛 is the flow behavior
index, dimensionless; k is flow consistency index, dyn·secn/ft2
71
c. Critical Reynolds number value for turbulent/ laminar transition: 𝑁𝑅𝑒𝑐 =2100
d.
Fanning friction factor:
For laminar flow, 𝑁𝑅𝑒 < 𝑁𝑅𝑒𝑐 , 𝑓 = 16/𝑁𝑅𝑒
For turbulent flow, 𝑁𝑅𝑒 > 𝑁𝑅𝑒𝑐
𝑓=
𝑎
𝑁𝑅𝑒 𝑏
;𝑎=
𝑙𝑜𝑔𝑛+3.93
50
;𝑏=
1.75−𝑙𝑜𝑔𝑛
7
…………………………...……………...……. (6.23)
e. Frictional pressure loss calculation inside drillstring, 𝛥𝑃𝑑𝑠 :
𝑑𝑝
𝑓𝑣𝑝2 𝜌
(𝑑𝐿 ) = 25.81𝐷 ……………………………………………………………………………. (6.24)
𝑝
𝑑𝑝
𝛥𝑃𝑑𝑠 = (𝑑𝐿 ) ∆𝐿…………….............................................................................................. (6.25)
Where (𝑑𝑝/𝑑𝐿) is the pressure gradient, psi/ft
 Annulus Flow
a. Annular velocity:
0.408𝑞
V𝑎 = (𝐷2 −𝐷2 )……………………………………………………………………….... (6.26)
2
1
Where 𝐷1 is the diameter of drill pipe, in; 𝐷2 is the diameter of casing, in.
b. Reynolds number:
N𝑅𝑒 =
928(𝐷2 −𝐷1 )𝑉𝑎 𝜌
𝜇𝑒
144𝑉𝑎 𝑛−1 2𝑛+1 𝑛
) ( 3𝑛 ) ;
2 −𝐷1
; 𝜇𝑒 = 100𝑘(𝐷
c. Critical Reynolds number value, 𝑁𝑅𝑒𝑐 = 2100
d. Fanning friction factor:
72
𝜃100
𝑛 = 0.657 log (
𝜃3
);k =
5.10𝜃100
170.2n
…(6.27)
Compare 𝑁𝑅𝑒 and 𝑁𝑅𝑒𝑐 to determine the flow regime, use the same procedure as in pipe flow, but
the friction factor for laminar flow should be changed as: 𝑓 = 24/𝑁𝑅𝑒 .
e.
Frictional pressure loss calculation in the annulus, 𝛥𝑃𝑎 , psi:
𝑓𝑣 2 𝜌
𝑑𝑝
(𝑑𝐿 ) = 25.81(𝐷𝑎 −𝐷 )………………………………………………………………………. (6.28)
2
1
𝑑𝑝
𝛥𝑃𝑎 = (𝑑𝐿 ) ∆𝐿 ……………............................................................................................... (6.29)
 Frictional pressure losses across the bit, ∆𝑃𝑏 , psi:
∆𝑃𝑏 = (𝐷2
156𝜌𝑞 2
2
2 2
𝑁1 +𝐷𝑁2 +𝐷𝑁3 )
……………………………………………………..…………….. (6.30)
Where DN1, DN2, DN3 are diameters of the three nozzles, in.
 The pump pressure, ∆𝑃𝑝 , psi:
∆𝑃𝑝 = ∆𝑃𝑠 + ∆𝑃𝑑𝑠 + ∆𝑃𝑏 + ∆𝑃𝑎 …………………………..……………………………... (6.31)
Where ∆𝑃𝑠 is the frictional pressure loss in the surface equipment, psi.
6.2.2
Hydraulics Simulation
A hydraulics simulation is conducted to predict the pump pressure in an actual well
operation by using the anti-freeze polymer system. The data comes from a well in Kharyaga
wells of Russia (Boyer and Szakolczai, 2001). The 5-in drilling pipe runs to 1622 m measured
depth. The intermediate casing of 13 3/8 inches was run to 1616 m depth. The anti-freeze
polymer system tested is 0.3% guar gum + 5% KCl + 5% NaCl + 30% glycerol. The mud weight
is 9.86 lb/gal (1.18g/cm3). The rheological data is taken from the lab experiment result. To
simplify the hydraulics simulation, the temperature is assumed to be constant all over the well
73
bore and it is approximate to 32℉ (0℃). The specific well architecture data are shown as Table
6.3. The calculated data for the designed anti-freeze polymer system is listed in Table 6.4.
Table 6.3.Engineering data from the well design
Drillpipe –5 in. 19.5 S-135 w/4.5 IF (6.75 in. ×3 in. connection): D1 = 5 in, Dp = 4.5 in
Casing 13 3/8 in. × 12.415 in.: D2 = 12.415 in
Length of well = 1616m (5302ft)
Bit: 10 5/8 in. w/3: 28/32 in (22.225 mm) jets
Δps = 0
Density (ρ) of designed anti-freeze polymer system = 9.86 lb/gal (1.18 g/cm3)
Rheological data of designed anti-freeze polymer system:
θ600 = 65, θ300 = 41, θ200 = 31, θ100 =20, θ6 = 3, θ3 = 2
From the simulation, the pump pressure of an actual drilling operation was predicted. The
estimated pump pressure refers to the power lost overcoming the friction through the drilling
fluid circulation, which is an important parameter in drilling engineering design. According to
Table 6.4, when the flow rate is 100 gal/min, the predicted by using anti-freeze guar gum (0.3%)
system is 45.04 psi. When flow rate is 665 gal/min, the pump pressure predicted by using antifreeze guar gum (0.3%) system is 622.17 psi.
74
Table 6.4.Simulated pump pressure with anti-freeze polymer drilling fluid
Q1=100 gal/min
Pipe Flow
Annular Flow
Flow behavior index
𝑛𝑝
0.66
𝑛𝑎
0.66
Flow consistency, dyn·secn/ft2
𝑘𝑝
3.32
𝑘𝑎
3.50
Pipe/ annular velocity, ft/s
𝑣𝑝
2.01
𝑣𝑎
0.32
Equivalent viscosity, cp
𝜇𝑒
101.86
𝜇𝑒
208.57
Reynolds number
𝑁𝑁𝑒
814
𝑁𝑁𝑒
103
Fanning friction factor
𝑓𝑝
0.02
𝑓𝑎
0.23
Pressure gradient, psi/ft
𝑑𝑝/𝑑𝐿
0.0068
𝑑𝑝/𝑑𝐿
0.0012
Pressure loss, psi
𝛥𝑝𝑑𝑠
35.89
𝛥𝑝𝑎
6.37
Pressure loss in bit, psi
𝛥𝑃𝑏
2.78
Pump pressure, psi
𝛥𝑝𝑝
45.04
Q2=665 gal/min
Pipe Flow
Annular Flow
Flow behavior index
𝑛𝑝
0.66
𝑛𝑎
0.66
Flow consistency, dyn·secn/ft2
𝑘𝑝
3.32
𝑘𝑎
3.50
Pipe/ annular velocity, ft/s
𝑣𝑝
13.40
𝑣𝑎
2.10
Equivalent viscosity, cp
𝜇𝑒
53.94
𝜇𝑒
108.90
Reynolds number
𝑁𝑁𝑒
10229
𝑁𝑁𝑒
1309
Fanning friction factor
𝑓𝑝
0.01
𝑓𝑎
0.02
Pressure gradient, psi/ft
𝑑𝑝/𝑑𝐿
0.0900
𝑑𝑝/𝑑𝐿
0.0042
Pressure loss, psi
𝛥𝑝𝑑𝑠
447.10
𝛥𝑝𝑎
22.11
Pressure loss in bit, psi
𝛥𝑃𝑏
122.96
Pump pressure, psi
𝛥𝑝𝑝
622.17
75
CHAPTER 7: FILTRATION CONTROL OF ANTI-FREEZE POLYMER SYSTEMS
7.1
Basic theory of filtration property
The main purpose of filtration control is preventing drilling fluid invasion into formation
due to an overbalance of hydrostatic pressure in the well. Filtration control can be achieved by
the formation of thin impermeable flexible filter cake on the borehole. The cake build-up aims at
plugging formation pores with bentonite and polymers. Exclusion of bentonite from the drilling
fluid complicates filter cake formation. In this case, the polymeric system should be enriched
with small size additives (compatible with permafrost drilling conditions) to block the formation
pores.
Filtration control in permafrost has a critical role. Filtrate (water) invasion into the
formation must be minimized since the presence of liquid water can impair the mechanical
property of frozen stratum and lead to instability of the wellbore. Therefore, when drilling in the
frozen stratum, the volume of filtrate must be controlled. Along with high quality filter cake,
osmotic control by maintaining a saturated drilling fluid can help to solve this problem.
Polymer solutions investigated as arctic drilling fluids are expected to have good
filtration control. In this Chapter, the filtration properties of polymer solutions were tested. The
influence of anti-freeze agent on the filtration performance of polymer solutions was also
investigated. The polymer or combination of polymers that provide the lowest volume of filtrate
was considered as the best filtration control agent. The rheological parameters of filtration
control agent combining viscosifier were also measured to testify their hole cleaning capacity
that conform the requirement of arctic drilling.
76
7.2
Filtration test of polymer solutions
From Chapter 5, the optimized concentrations of polymer solutions have been selected
(Table 5.8). Each polymer solution was prepared and put into the API filter press for filtration
testing. The volume of filtrate, defined as that discharged by API filter press in 30 minutes, was
measured. When the polymer solutions were tested without additives, the results indicated that
among the polymer solutions, only 0.3% guar gum solution has a good filtration control (Table
6.1). Its filtration volume in 30 minutes was 19.5ml. The other polymer solutions all had
filtration volume that is higher than 100 ml, which means they were not able to manage proper
filtration control.
Table 7.1.Filtration volumes of polymer solutions
Optimized
polymer
0.3% guar
gum
0.2%
xanthan
gum
1% modified
starch
0.6% MC
M0387
0.5% MF
PAC-LV
Filtration
19.5ml
>100ml
>100ml
>100ml
>100ml
The presence of additives can alter the filtration properties of the polymer solution. In
particular, viscosifiers are generally needed in formulating the drilling fluid. Therefore, in the
next set of experiments, the combination of viscosifier and filtration control agent will be tested
to see if it can offer a desirable filtration control.
The viscosifiers (0.2% xanthan gum and 1% modified starch) and filtration control agents
(0.6% MC M0387 and 0.5% MF PAC-LV) were paired. A total of four combinations are tested:
0.2% xanthan gum + 0.6% MC M0387, 0.2% xanthan gum + 0.5% MF PAC-LV, 1% modified
starch + 0.6% MC M0387 and 1% modified starch + 0.5% MF PAC-LV. Each polymer
77
combination was prepared and put into the API filter press for filtration test. The 30 minutes
filtrate volume of polymer combinations was measured (Table 7.2).
Table 7.2.Filtration volumes of polymer combinations
Optimized
polymer
0.2% xanthan gum
+ 0.6%
MC M0387
0.2% xanthan gum
+ 0.5%
MF PAC-LV
1% modified
starch + 0.6%
MC M0387
1% modified
starch + 0.5%
MF PAC-LV
Filtration
19.5 ml
20.5 ml
> 100 ml
> 100 ml
Two combinations containing xanthan gum demonstrated good filtration control. The
filtrate volumes were 19.5 ml and 20.5 ml for 0.2% xanthan gum + 0.6% MC M0387 and 0.2%
xanthan gum + 0.5% MF PAC-LV respectively. In contrast, two combinations containing
modified starch were not able to decrease the water loss. The filtrate volume of each was greater
than 100 ml. This result indicated that in cooperating with xanthan gum, the filtration control
agent is effective to enhance the filtration control.
From the experiment result from Chapter 5, increasing xanthan gum concentration
increases the viscosity of xanthan gum solution, but adding anti-freeze agent decreases the
viscosity of xanthan gum solution. In next sets of experiment, the filtration property of the
polymer combinations in response to anti-freeze agent was investigated first. The rheological
parameters will be tested later to verify if the desired rheological properties of the anti-freeze
polymer system were still maintained.
78
7.3
Filtration of polymers in response to anti-freeze base
In the following set of experiments, the filtration control property of the polymer
combinations in response to anti-freeze agent was investigated.
Three polymer combinations 0.2% xanthan gum + 0.6% MC M0387; 0.2% xanthan gum +
0.5% MF PAC-LV and 0.3% guar gum were mixed with the anti-freeze agent: 5% NaCl + 5%
KCl + 30% glycerol. The three anti-freeze polymer systems (labeled as AFP1, AFP2 and AFP3)
were tested in the API filter press, the 30 minutes filtrate volume of three systems was measured
at room temperature (Table 6.3).
Table 7.3.Filtration volumes of anti-freeze polymer solutions
Optimized polymer
AFP1
AFP2
AFP3
Filtration
9.0 ml
9.5 ml
16.5 ml
Through the filtration tests, all three anti-freeze polymer systems have good filtration
control. Comparing Table 7.2 and 7.3, the filtrate volume of 0.2% xanthan gum + 0.6% MC
M0387 has decreased from 19.5 ml to 9.0 ml indicating that adding the anti-freeze agent
enhanced the filtration control ability of polymer solutions. The possible mechanism can be
explained by the assumption that the glycerol encapsulated the un-hydrated polymers to form a
film of fine particles, which sealed the flow channel on the filter paper, hence reduced the filtrate
volume.
79
7.4
Rheology test of anti-freeze polymer systems
Although the filtration control of the three anti-freeze polymer systems is acceptable, the
rheological performance needs to be considered. The rheological properties of the three systems
were tested under different temperature conditions. Table 7.4 shows the test result of PV, YP and
YP/PV ratio.
Table 7.4.Rheological parameters of anti-freeze polymer solutions
0.2% xanthan gum + 0.6% MC M0387 + anti-freeze agent
Temperature, °C
PV (cp)
YP (lb/100ft2)
YP/PV (lb/100ft2∙cp)
25
14
5
0.36
10
16
10
0.63
0
28
22
0.79
-20
36
59
1.64
0.2% xanthan gum + 0.5% PAC + anti-freeze agent
Temperature, °C
PV (cp)
YP (lb/100ft2)
YP/PV (lb/100ft2∙cp)
25
20
8
0.4
10
39
21
0.54
0
48
33
0.69
-20
69
57
0.83
0.3% guar gum + anti-freeze agent
Temperature, °C
PV (cp)
YP (lb/100ft2)
YP/PV (lb/100ft2∙cp)
25
15
8
0.53
0
24
17
0.71
-10
33
21
0.64
-20
39
32
0.82
Under same temperature condition, the polymer combination solution has higher value of
rheological parameters than the single polymer solution. For example, the PV and YP of 0.2%
80
xanthan gum + 0.5% PAC + anti-freeze agent solution were lower than the PV and YP of 0.2%
xanthan gum + anti-freeze agent and 0.5% PAC + anti-freeze agent solutions. This is because the
combination of polymer increased the concentration of long chain polymers. The hydrated and
cross-linked polymer molecules generated higher inner friction and molecular attraction of
drilling fluid thus increased the PV and YP. The rheological parameters for three anti-freeze
polymer solutions were desirable for practical drilling operation. The YP/PV ratios were all close
to the range of 0.7 ~ 1 lb/100ft2∙cp, which indicated desirable rheology. By far, the basic
formulation of low-toxic non-solid anti-freeze polymer drilling fluid is designed as follows:
1. Xanthan gum (0.2%) + MC M0387 (0.6%) + NaCl (5%) + KCl (5%) + Glycerol (30%)
2. Xanthan gum (0.2%) + MF PAC-LV (0.5%) + NaCl (5%) + KCl (5%) + Glycerol (30%)
3. Guar gum (0.3%) + NaCl (5%) + KCl (5%) + Glycerol (30%)
7.5
Hydraulics Simulation
A hydraulics simulation is conducted to compare the performance of the two newly
formulated anti-freeze polymer drilling fluids: 0.2% xanthan gum + 0.6% MC M0387 (AFP 1)
and 0.2% xanthan gum + 0.5% MF PAC-LV (AFP 2). The process is the same as the simulation
for anti-freeze guar gum (0.3%) drilling fluid (Shown as Section 6.2.2). The well data comes
from the same well in Kharyaga, Russia (Table 7.5). The intermediate casing of 13 3/8 inches
was run to 5302 ft depth. The mud weight of the AFP1 and AFP2 is the same, which is 9.89
lb/gal (1.20g/cm3). The rheological data is taken from the experiment result in Section 7.4. To
simplify the hydraulics simulation, the temperature is assumed to be constant all over the well
bore and it is approximate to 32℉ (0℃). The calculated data for AFP1 and AFP2 is listed in
Table 7.6 and 7.7 respectively.
81
Table 7.5.Engineering data from the well design
Drillpipe –5 in. 19.5 S-135 w/4.5 IF (6.75 in. ×3 in. connection): D1 = 5 in, Dp = 4.5 in
Casing 13 3/8 in. × 12.415 in.: D2 = 12.415 in
Length of well = 1616m (5302ft)
Q1 = 100 gallon/min (0.0063 m3/s)
Q2 = 665 gallon/min (0.0042 m3/s)
Bit: 10 5/8 in. w/3: 28/32 in (22.225 mm) jets
Δps = 0
Density (ρ) of AFP1 = 9.89 lb/gal (1.20 g/cm3)
Rheological data of AFP1:
θ600 = 78, θ300 = 50, θ200 = 30, θ100 = 18, θ6 =1.5, θ3 = 1
Density (ρ) of AFP2 = 9.89 lb/gal (1.20 g/cm3)
Rheological data of AFP2:
θ600 = 129, θ300 = 81, θ200 = 61, θ100 =37, θ6 = 4, θ3 = 2
82
Table 7.6.Simulated pump pressure with AFP1
Q1=100 gal/min
Pipe Flow
Annular Flow
Flow behavior index
𝑛𝑝
0.64
𝑛𝑎
0.82
Flow consistency index
𝑘𝑝
4.68
𝑘𝑎
1.33
Pipe/ annular velocity, ft/s
𝑣𝑝
2.01
𝑣𝑎
0.32
Equivalent viscosity, cp
𝜇𝑒
131.97
𝜇𝑒
102.38
Reynolds number
𝑁𝑁𝑒
630
𝑁𝑁𝑒
210
Fanning friction factor
𝑓𝑝
0.03
𝑓𝑎
0.11
Pressure gradient
𝑑𝑝/𝑑𝐿
0.0088
𝑑𝑝/𝑑𝐿
0.0006
Pressure loss, psi
𝛥𝑝𝑑𝑠
46.51
𝛥𝑝𝑎
3.13
Pressure loss in bit, psi
𝛥𝑃𝑏
2.79
Pump pressure, psi
𝛥𝑝𝑝
52.42
Q2=665 gal/min
Pipe Flow
Annular Flow
Flow behavior index
𝑛𝑝
0.64
𝑛𝑎
0.82
Flow consistency index
𝑘𝑝
4.69
𝑘𝑎
1.33
Pipe/ annular velocity, ft/s
𝑣𝑝
13.40
𝑣𝑎
2.10
Equivalent viscosity, cp
𝜇𝑒
67.00
𝜇𝑒
73.45
Reynolds number
𝑁𝑁𝑒
8259
𝑁𝑁𝑒
1947
Fanning friction factor
𝑓𝑝
0.01
𝑓𝑎
0.01
Pressure gradient
𝑑𝑝/𝑑𝐿
0.0935
𝑑𝑝/𝑑𝐿
0.0028
Pressure loss, psi
𝛥𝑝𝑑𝑠
495.52
𝛥𝑝𝑎
14.91
Pressure loss in bit, psi
𝛥𝑃𝑏
123.34
Pump pressure, psi
𝛥𝑝𝑝
633.76
83
Table 7.7.Simulated pump pressure with AFP2
Q1=100 gal/min
Pipe Flow
Annular Flow
Flow behavior index
𝑛𝑝
0.67
𝑛𝑎
0.83
Flow consistency index
𝑘𝑝
6.29
𝑘𝑎
2.63
Pipe/ annular velocity, ft/s
𝑣𝑝
2.01
𝑣𝑎
0.32
Equivalent viscosity, cp
𝜇𝑒
197.32
𝜇𝑒
204.55
Reynolds number
𝑁𝑁𝑒
421
𝑁𝑁𝑒
105
Fanning friction factor
𝑓𝑝
0.04
𝑓𝑎
0.23
Pressure gradient
𝑑𝑝/𝑑𝐿
0.0131
𝑑𝑝/𝑑𝐿
0.0012
Pressure loss, psi
𝛥𝑝𝑑𝑠
69.54
𝛥𝑝𝑎
6.24
Pressure loss in bit, psi
𝛥𝑃𝑏
2.79
Pump pressure, psi
𝛥𝑝𝑝
75.78
Pipe Flow
Annular Flow
Q2=665 gal/min
Flow behavior index
𝑛𝑝
0.67
𝑛𝑎
0.83
Flow consistency index
𝑘𝑝
6.31
𝑘𝑎
2.63
Pipe/ annular velocity, ft/s
𝑣𝑝
13.4
𝑣𝑎
2.10
Equivalent viscosity, cp
𝜇𝑒
106.00
𝜇𝑒
148.94
Reynolds number
𝑁𝑁𝑒
5220
𝑁𝑁𝑒
960
Fanning friction factor
𝑓𝑝
0.01
𝑓𝑎
0.02
Pressure gradient
𝑑𝑝/𝑑𝐿
0.1093
𝑑𝑝/𝑑𝐿
0.0057
Pressure loss, psi
𝛥𝑝𝑑𝑠
579.60
𝛥𝑝𝑎
30.24
Pressure loss in bit, psi
𝛥𝑃𝑏
123.34
Pump pressure, psi
𝛥𝑝𝑝
733.17
Comparing Table 7.6 and 7.7, when the flow rate is 100 gal/min, the pump pressure
required by AFP1 is 52.42 psi, while the pump pressure predicted by using AFP2 is 75.78psi.
When flow rate is 665 gal/min, the pump pressure required by AFP1 is 633.76 psi, while the
84
pump pressure predicted by using AFP2 is 733.71 psi. These results indicate that under the same
engineering condition, AFP1 requires lower pump pressure than AFP2. If compare the above
results with Table 6.4 (show as Section 6.2.2), we can find that the pump pressure required by
anti-freeze guar gum (0.3%) drilling fluid is the lowest.
7.6
Cuttings carrying capacity
One of the principal functions of drilling fluid is cleaning the well bottom and carrying the
cuttings to the surface. Besides the hydraulics, the hole cleaning ability of drilling fluid also
depends on the rheological properties. To estimate the cutting carrying capacity, a method called
Cutting Carrying Index (CCI) is utilized. The equations for calculating the CCI are as follows:
𝐶𝐶𝐼 =
𝐾𝜌𝑉𝑎
…………………………………………………………………………..…..….. (7.1)
400000
𝐾 = (511)1−𝑛 (𝑃𝑉 + 𝑌𝑃)……………………………………………………….....…………. (7.2)
𝑛 = 3.32𝑙𝑜𝑔
(2𝑃𝑉+𝑌𝑃)
(𝑃𝑉+𝑌𝑃)
…………………………………………………………..….………….. (7.3)
Where: 𝑉𝑎 - annular velocity, ft/min; 𝜌 - mud weight, ppg; K - Power law Constant; PV- plastic
viscosity, cp; YP - yield point, lb/100ft2; n - flow behavior index.
Judging criteria:
If CCI is equal to 0.5 or less, the hole cleaning is poor and the hole problem may be seen.
If CCI is equal to 1.0 or greater, it indicated that hole cleaning is good.
The CCI of the three anti-freeze polymer drilling fluids was calculated and applied to
evaluate their hole cleaning ability. The anti-freeze drilling fluid xanthan gum (0.2%) + MC
85
M0387 (0.6%) + NaCl (5%) + KCl (5%) + Glycerol (30%) is labeled as AFP 1, the mud weight
is 9.89 lb/gal; Xanthan gum (0.2%) + PAC (0.5%) + NaCl (5%) + KCl (5%) + Glycerol (30%) is
labeled as AFP2, the mud weight also is 9.89 lb/gal; Guar gum (0.3%) + NaCl (5%) + KCl (5%)
+ Glycerol (30%) is labeled as AFP3, the mud weight is 9.86 lb/gal. The annular velocity used is
100 ft/min, which is an empirical value of laminar flow in annulus. The rheological data is
shown as Table 7.4. The calculated results of CCI are shown as Table 7.8
Table 7.8.CCI of three anti-freeze polymer drilling fluids under different temperature
Drilling fluid
Temperature
25°C
0°C
-20°C
AFP1
0.17
1.16
2.79
AFP2
0.28
1.56
3.14
AFP3
0.32
1.07
1.75
For the three drilling fluids, the CCI is all greater than 1 when the temperatures is at or
below 0°C, while the CCI is less than 1 when temperature is at 20°C. The results indicate that the
three anti-freeze drilling fluids are able to provide good hole cleaning when drilling in
permafrost section. When drilling into the formation below permafrost table that has formation
temperature above 0°C, the concentration of viscosifiers need to be increased according to the
request of operation, in order to maintain the cutting carrying capacity of drilling fluid.
86
CHAPTER 8: SUMMARY, CONCLUSIONS AND RECOMMENDATIONS
8.1
Summary
In this study, specific approaches in low-toxic non-solid anti-freeze drilling fluid design
and optimization are conducted to deal with the issues of heat transfer, well stability, hole
cleaning and drilling efficiency involved in arctic drilling. The published information regarding
arctic drilling engineering and research of anti-freeze drilling fluid is reviewed to select the
components of low-toxic anti-freeze agent for drilling fluids. 30% glycerol was selected to be the
reinforcing anti-freeze agent. Tests were conducted to verify the concentration of NaCl and KCl
can be reduced to 5% each while maintaining a freezing point below -20 °C.
The polymer xanthan gum, guar gum, MF PAC-LV, modified starch and methylcellulose
M0387 were selected to investigate the influence of anti-freeze agent on the rheological
performance and filtration control of polymer. The formulated polymer systems are
demonstrated to be able to generate desirable viscosity and yield point to provide efficient hole
cleaning under low temperature environment (-20 °C ~ 0 °C). The desirable filtration control is
also proved by generating the minimized volume of filtrate.
A simple and direct approach has been presented for selecting the best rheological model
for any non-Newtonian fluid according to the lowest EAAP criteria. API Power law model is
confirmed to describe sufficiently the rheology of most polymer fluids. A hydraulics simulation
was performed in comparing the frictional pressure loss of the three designed polymer systems.
The results indicate that under the same engineering condition, the anti-freeze guar gum systems
require lower pump pressure than the other two polymer drilling fluids.
87
8.2
Conclusions
Based on the experimental results obtained from this study, the following conclusions
were made.
1.
Polymer solutions investigated as Arctic drilling fluids are desired to be non-solid muds.
2.
Under the combined action of NaCl, KCl and glycerol, the polymer system has favorable
anti-freeze ability, which suppresses the freezing point to be below -20 °C.
3.
Under the condition of same concentration or same temperature, the PV of natural gum
polymer (xanthan gum and guar gum) is generally lower than cellulose derivative
polymer’s (MF PAC-LV and MC0387), but the YP is higher. This indicates that the natural
gum polymer is better than the cellulose derivative polymer for viscosity control.
4.
The filtration control property of 0.6% MC M0387 and 0.5% MF PAC-LV solutions are
greatly enhanced by combining with 0.2% xanthan gum; their filtrate volume are also
minimized after adding anti-freeze agent 5%NaCl + 5%KCl + 30% Glycerol.
5.
The formulations for three anti-freeze non-solid polymer drilling fluids are finalized:
i.
Xanthan gum (0.2%) + MC M0387 (0.6%) + NaCl (5%) + KCl (5%) + Glycerol
(30%)
ii.
Xanthan gum (0.2%) + PAC (0.5%) + NaCl (5%) + KCl (5%) + Glycerol (30%)
iii.
Guar gum (0.3%) + NaCl (5%) + KCl (5%) + Glycerol (30%)
The freezing points of the three drilling fluids are all below -20 °C. Under 0 °C, the
YP/PV ratios are all higher than 0.7 lb/100ft2∙cp.
6.
The anti-freeze polymer drilling fluids are proved to have desirable hole cleaning capacity
under 0 °C, which indicated by the criterion: CCI > 1.0.
88
8.3
Recommendations for future research
In this research, we assume Artic drilling operation proceeds under LTLP condition;
therefore, the experiments were only conducted under the standard pressure (1 atmosphere).
However, the freezing point of water and solubility of salts is reported to be affected by pressure,
it is necessary to investigate the fluctuation of freezing point and salt precipitation with respect to
the change of pressure. In addition to that, for the future research, we also need to consider about
the following issues:
1.
The designed anti-freeze polymer drilling fluids generate relatively high YP at -20 °C (YP >
35 lb/100ft2), while the YP/PV ratio is relatively low at 25 °C (YP/PV ratio < 0.7
lb/100ft2∙cp); further experiments are necessary to investigate the additives to reduce the
difference of rheology at different temperature.
2.
Filtration test of polymer solution are only tested under room temperature, for the present
experimental facilities cannot be operated under low temperature condition. Further
investigation is needed to find the testing method.
3.
The shale inhibitive ability is another important property of drilling fluid in drilling arctic
area; further investigation and experiments on the inhibitive ability of anti-freeze drilling
fluid should be carried out.
89
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96
APPENDIX A - DATA SPREADSHEETS
97
Table A1 -Test result of rheology of xanthan gum solution with different concentration
Temperature
PV
0.20%
YP
0.30%
YP
YP/PV
PV
(cp)
(lb/100ft2)
(lb/100ft2∙cp)
(cp)
lb/100ft2
(lb/100ft2∙cp)
YP/PV
23 °C
11
7
0.63
10
15
1.50
10 °C
12
13
1.08
11
15
1.36
5 °C
12
15
1.00
10
18
1.80
0 °C
14
14
1.25
11
20
1.82
PV
0.60%
YP
YP/PV
PV
1%
YP
(cp)
(lb/100ft2)
(lb/100ft2∙cp)
(cp)
(lb/100ft2)
(lb/100ft2∙cp)
23 °C
10
31
3.10
22
44
2.00
10 °C
20
45
2.25
26
47
1.81
5 °C
24
47
1.96
27
48
1.78
0 °C
25
51
2.04
28
54
1.93
PV
1.20%
YP
Temperature
Temperature
YP/PV
(cp)
(lb/100ft )
(lb/100ft2∙cp)
23 °C
35
92
2.63
10 °C
54
109
2.02
5 °C
55
125
2.27
0 °C
65
126
1.94
2
98
YP/PV
Table A2 -Rheology of guar gum solution with different concentration
Temperature
PV
0.30%
YP
0.50%
YP
YP/PV
PV
(cp)
(lb/100ft2)
(lb/100ft2∙cp)
(cp)
(lb/100ft2)
(lb/100ft2∙cp)
23°C
7
1
0.14
12
8
0.67
15°C
10
9
0.90
14
27
1.93
10°C
5°C
10
11
11
11
1.10
1.00
16
17
28
29
1.75
1.71
0°C
12
13
1.18
18
30
1.67
1.30%
YP
Temperature
PV
0.90%
YP
YP/PV
YP/PV
PV
(cp)
(lb/100ft2)
(lb/100ft2∙cp)
(cp)
(lb/100ft2)
(lb/100ft2∙cp)
YP/PV
23°C
19
57
3.00
29
136
4.69
15°C
23
77
3.35
44
138
3.14
10°C
25
90
3.60
47
144
3.06
5°C
0°C
26
27
92
94
3.54
3.48
49
51
152
160
3.10
3.14
Table A3 -Rheology of modified starch solution with different concentration
Temperature
PV
(cp)
23°C
15°C
10°C
5°C
0°C
Temperature
15
17
19
21
22
PV
(cp)
23°C
15°C
10°C
5°C
0°C
25
30
32
35
42
1.00%
YP
YP/PV
(lb/100ft ) (lb/100ft ∙cp)
2
12
12
13
14
16
2.00%
YP
2
0.80
0.71
0.68
0.67
0.73
YP/PV
(lb/100ft ) (lb/100ft2∙cp)
2
18
21
24
26
29
0.72
0.70
0.73
0.72
0.69
99
PV
1.50%
YP
YP/PV
(cp)
(lb/100ft )
(lb/100ft2∙cp)
23
27
30
32
35
16
20
22
25
27
0.70
0.74
0.76
0.81
0.77
2
Table A4 -Rheology of M4170 methylcellulose solution with different concentration
Temperature
2.40%
PV
YP
YP/PV
PV
3.00%
YP
YP/PV
(cp) (lb/100ft2) (lb/100ft2∙cp) (cp) (lb/100ft2) (lb/100ft2∙cp)
23°C
21
2
0.10
36
5
0.14
15 °C
28
5
0.18
47
9
0.19
10 °C
31
7
0.23
52
13
0.25
5 °C
37
8
0.22
68
14
0.21
0 °C
Temperature
43
10
0.23
71
16
0.23
3.60%
PV
YP
YP/PV
(cp) (lb/100ft2) (lb/100ft2∙cp)
23°C
21
2
0.10
15 °C
28
5
0.18
10 °C
31
7
0.23
5 °C
37
8
0.22
0 °C
43
10
0.23
Table A5 -Rheology of M0262 methylcellulose solution with different concentration
Temperature
PV
1.00%
YP
1.20%
YP/PV
PV
YP
YP/PV
(cp) (lb/100ft2) (lb/100ft2∙cp) (cp) (lb/100ft2) (lb/100ft2∙cp)
23°C
15°C
10°C
5°C
0°C
31
33
43
48
52
8
11
14
18
23
0.26
0.33
0.33
0.38
0.44
100
46
64
71
77
91
15
27
35
38
50
0.33
0.42
0.49
0.49
0.55
Table A6 -Rheology of M0387 methylcellulose solution with different concentration
Temperature
0.60%
PV
YP
0.80%
YP/PV
PV
YP
YP/PV
(cp) (lb/100ft2) (lb/100ft2∙cp) (cp) (lb/100ft2)
23 °C
15 °C
10 °C
5 °C
0 °C
Temperature
21
26
29
34
36
4
8
13
16
20
0.19
0.31
0.45
0.47
0.56
34
39
49
54
55
(lb/100ft2∙cp)
16
23
26
38
46
0.47
0.59
0.53
0.70
0.84
1.00%
PV
YP
YP/PV
(cp) (lb/100ft2) (lb/100ft2∙cp)
23 °C
15 °C
10 °C
5 °C
0 °C
52
61
65
70
75
30
41
57
64
68
0.58
0.67
0.88
0.92
0.91
Table A7 -Rheology of MF PAC LV solution with different concentration
Temperature
PV
1.00%
YP
1.20%
YP/PV
PV
YP
YP/PV
(cp) (lb/100ft2) (lb/100ft2∙cp) (cp) (lb/100ft2) (lb/100ft2∙cp)
23°C
15°C
10°C
5°C
0°C
22
27
29
33
35
6
11
18
19
21
0.27
0.41
0.62
0.56
0.60
101
28
35
38
42
46
12
17
24
30
37
0.43
0.49
0.63
0.71
0.80
Table A8 -Rheology of 0.2% xanthan gum solution
YP (lb/100ft2)
PV (cp)
Temperature
23 °C
10 °C
5 °C
0 °C
-10 °C
-20 °C
Temperature
23 °C
10 °C
5 °C
0 °C
-10 °C
-20 °C
Polymer
AFS1
AFS2
6
8
9
12
frozen
6
8
NA
NA
NA
NA
12
13
16
17
19
31
YP/PV (lb/100ft2∙cp)
Polymer
AFS1
AFS2
0.64
0.17
0.40
1.08
NA
NA
1.25
NA
NA
1
0.17
0.35
frozen
0.19
0.31
0.21
0.35
AFS3
Polymer
AFS1
AFS2
AFS3
15
NA
NA
26
35
37
12
17
18
16
frozen
1
NA
NA
2
3
6
2
NA
NA
3
4
7
6
NA
NA
9
11
13
AFS3
0.25
NA
NA
0.23
0.24
0.23
Table A9 -Rheology of 0.3% guar gum solution
YP (lb/100ft2)
PV (cp)
Temperature
23 °C
10 °C
5 °C
0 °C
-10 °C
-20 °C
Temperature
23 °C
10 °C
5 °C
0 °C
-10 °C
-20 °C
Polymer
7
10
11
12
frozen
AFS1
AFS2
15
16
NA
NA
NA
NA
24
27
33
33
39
52
YP/PV (lb/100ft2∙cp)
Polymer
AFS1
AFS2
0.07
0.53
0.94
0.56
NA
NA
0.51
NA
NA
0.51
0.71
0.85
frozen
0.64
0.79
0.82
0.76
AFS3
Polymer
AFS1
AFS2
AFS3
20
NA
NA
35
47
90
0.511
5.621
5.621
6.132
frozen
8
NA
NA
17
21
32
15
NA
NA
23
26
37
19
NA
NA
27
29
45
AFS3
0.95
0.77
NA
0.77
0.62
0.50
102
Table A10 -Rheology of 1% modified Starch solution
YP (lb/100ft2)
PV (cp)
Temperature
Polymer
AFS1
AFS2
AFS3
Polymer
AFS1
AFS2
AFS3
23 °C
12
9
13
14
2
1
2
2
10 °C
14
NA
NA
NA
2
NA
NA
NA
5 °C
17
NA
NA
NA
4
NA
NA
NA
0 °C
18
20
23
28
6
5
4
7
-10 °C
frozen
27
28
39
frozen
6
6
16
38
47
51
14
25
31
-20 °C
YP/PV (lb/100ft ∙cp)
2
Temperature
23 °C
Polymer
0.17
AFS1
0.06
AFS2
0.14
AFS3
0.15
10 °C
0.14
NA
NA
NA
5 °C
0.24
NA
NA
NA
0 °C
0.33
0.13
0.25
0.17
-10 °C
frozen
0.11
0.41
0.21
0.19
0.31
0.48
-20 °C
Table A11 -Rheology of 0.5% MF PAC LV
YP (lb/100ft2)
PV (cp)
Temperature
23 °C
10 °C
5 °C
0 °C
-10 °C
-20 °C
Temperature
23 °C
10 °C
5 °C
0 °C
-10 °C
-20 °C
Polymer
AFS1
AFS2
AFS3
Polymer
AFS1
AFS2
AFS3
14
19
21
22
frozen
11
NA
NA
22
31
35
13
NA
NA
24
35
45
15
NA
NA
28
42
49
12
13
14
16
frozen
2
NA
NA
6
7
11
4
NA
NA
7
9
12
5
NA
NA
8
10
14
YP/PV (lb/100ft2∙cp)
Polymer
AFS1
AFS2
0.86
0.09
0.31
0.68
NA
NA
0.67
NA
NA
0.73
0.14
0.29
frozen
0.15
0.26
0.16
0.27
AFS3
0.33
NA
NA
0.29
0.24
0.29
103
Table A12 -Rheology of 0.6% M0387 methylcellulose
YP (lb/100ft2)
PV (cp)
Temperature
23 °C
10 °C
5 °C
0 °C
-10 °C
-20 °C
Temperature
23 °C
10 °C
5 °C
0 °C
-10 °C
-20 °C
Polymer
19
28
34
36
frozen
AFS1
AFS2
10
8
NA
NA
NA
NA
14
13
33
20
35
41
YP/PV (lb/100ft2∙cp)
Polymer
AFS1
AFS2
0.26
0.40
0.38
0.50
NA
NA
0.47
NA
NA
0.56
0.79
0.54
frozen
0.61
0.50
0.55
0.32
AFS3
Polymer
AFS1
AFS2
AFS3
7
NA
NA
12
17
23
5
14
16
20
frozen
4
NA
NA
11
20
30
3
NA
NA
7
10
13
2
NA
NA
3
4
5
AFS3
0.33
NA
NA
0.25
0.24
0.22
104
APPENDIX B - MATERIAL SAFETY DATA SHEET
105
Figure B1- MSDS of Xanthan gum
106
Figure B2- MSDS of Guar gum
107
Figure B3- MSDS of Modified Starch
108
Figure B4- MSDS of MF PAC LV
109
Figure B5- MSDS of M0387
110
Figure B6- MSDS of Glycerol
111
APPENDIX C- PRODUCT DATA SHEET
112
Figure C1- Product data of Xanthan gum
113
Figure C2- Product data of Guar gum
114
Figure C3- Product data of Modified Starch
115
Figure C4- Product data of MF-PAC LV
116