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EXPERIMENTAL STUDY OF THE EFFECT OF CO2 GAS KICK, TEMPERATURE AND
AGING TIME ON WATER BASED FLUID PROPERTIES
Experiment Findings · April 2013
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EXPERIMENTAL STUDY OF THE EFFECT OF
CO2 GAS KICK, TEMPERATURE AND AGING
TIME ON WATER BASED FLUID PROPERTIES
BY
OKORO FAITH EFEREMO
APRIL, 2013
ABSTRACT
There might be a possibility of CO2 leakage from the storage reservoir during carbon
sequestration and storage (CSS) process and this may lead to kick in nearby reservoir being
drilled. The CO2 kick, when it comes into contact with the drilling mud, will tend to alter the
properties of the drilling mud. The effect in the properties of the drilling mud could result into
failure of the drilling programme. This experimental research work studied the effect of CO2
kick, temperature and aging on the properties of water based drilling. A simple-based mud was
prepared and the properties of the mud were investigated as CO2 is injected into the mud at
interval to simulate CO2 gas kick during drilling. The measured properties of the injected mud
indicated that there was a 18% reduction in the density of the mud upon CO2 injection within the
first 11days.That is, low density would result into pressure under-balance resulting into further
influx of the CO2 to the well been drilled and this is dangerous for the drilling operation
This research also shows that there was a corresponding 75.23% reduction in the viscosity of the
mud within the first 12days of contact with CO2 which makes the mud totally ineffective in its
ability to clean the well and transport drill cuttings to surface and this will result into lower
drilling rate and higher drilling cost. After the first 11 days of CO2 influx, the density and
viscosity of the drilling mud remains constant and this is an indication that a drilling mud, when
reconditioned with a viscosifier, can be reused after some days of CO2 contamination without a
further CO2 kick altering its density and viscosity properties. The research also indicated that the
pH of the mud reduces gradually turning an initial basic mud to a slightly acidic mud. This is an
indication of possible reduction in equipment corrosion. The resistivity of the mud also increased
58.8% which is an indication of reduced ionic activities as a result of reactions between the
injected CO2 and the mud.
It is also evident from the research findings that plastic viscosity and yield point decrease
steadily with increase in temperature for all values of aging time. It is also observed as well that
viscosity at a given temperature decreases with increase in aging time. It is also observed from
this research that viscosity, yield point, gel strength and shear stress at a given shear rate
decrease with increase in temperature and aging time.
1.0 INTRODUCTION
The success of any drilling activity is based on details from the drilling fluid. Therefore the
successful completion of an oil well depends on the drilling fluid. A drilling fluid or mud is any
fluid that is used in a drilling operation Wells have different conditions, thus the drilling must be
able to cope with these conditions. For this to be successful, the composition of mud must be
varied with its properties.
These various properties are affected by contaminants. A contaminant is any type of material
(solid, liquid and gas) that has a detrimental effect on the physical or chemical characteristics of
a drilling fluid Contaminant can lead to unfavorable rheological properties and slow the drilling
rate. Eventually, the contaminant shows its effect by altering the fluid properties. In this study,
the contaminant is carbon dioxide.
Most drilling fluid formulations contain a base liquid and additives which must be dissolved or
mechanically dispersed into the liquid to form a homogenous fluid. The resulting fluid may
contain one or more of the following: water-dispersible (soluble) polymers or resins, clays or
other insoluble but dispersible fine solids and soluble salts. The fluids are mixed or sheared for
the number of times appropriate to achieve a homogenous mixture and are then set aside to
“age”. Aging of drilling fluid is the process in which a drilling fluid sample previously subjected
to a period of shear is allowed to more fully develop its rheological and filtration properties.
Aging takes place when mud is left inactive for example during tripping. Aging is done under
conditions which vary from static to dynamic and from ambient to highly elevated temperatures.
Drilling fluids satisfy many needs in their capacity to do the following: 1) Removal of Drill
Cuttings, (2) Control Formation Pressure, (3) Stabilizing the wellbore, (4) Cool and lubricate the
bit, (5) Transmit hydraulic horsepower to bit (6) Support Weight of Tubulars, (7)Minimize
Formation Damage, (8) Reducing Environmental Impact.
Annis [1] investigated the changes in rheological property with time and temperature up to
3000F by a concentric-cylinder, rotational viscometer of the Fann type. His experiments covered
the effects of temperature and aging on shear rate – shear stress , gel strength and viscosity. The
study concluded that high temperature causes flocculation of bentonite clays, resulting in high
yield points, high viscosities at low shear rates, high gel strengths and a permanent thickening of
the mud. He added that proper treatment of bentonite mud with NaOH and lignosulphate reduces
the effect of dispersion and flocculation at high temperature.
Alderman et al [2] carried out experiments with water-base mud to study the rheology at
temperatures up to 2660F and pressures up to 145000psi. They concluded that high shear
viscosity decreases with increasing temperature in a similar manner for all drilling fluids
examined and increases with pressure to an extent which depend on mud density. Yield stress is
essentially independent of pressure and weakly dependent on temperatures. Their study did not
simulate
the
bottom-hole
conditions
and
did
not
consider
the
aging
effect.
Mohammed Shahjahan Ali [3], later wrote a thesis from a laboratory investigation on the effect
of high temperature (4900F) and aging time of 30days on water-base mud properties using the
HTHP viscometer, baroid roller oven (dynamic aging) and distilled water as the continuous
phase.The result shows a decrease in viscosity, yield point and gel strength with the increase in
temperature for all values of aging time. He concluded that shear stress for a particular
temperature increases with increase in shear rate, but shear stress at a given shear rate decreases
with increase in temperature. Viscosity, yield point and gel strength at a given temperature
increase with aging time and aging effects are diminishing with the increase in aging time. Shear
stress at a given shear rate increases with aging time and aging effects decrease with the increase
in aging time.
Shokoya et al [4] conducted a study on the rheology and corrosivity of water-base drilling fluid
under simulated downhole conditions. The rheological property and corrosion behavior
relationship of mild steel type 1018 in a typical drilling fluid used in deep drilling and hot wells
was studied. The tests were conducted under conditions that simulate flow, temperature, and
pressure encountered during drilling operations. Physical properties that were considered are:
shear stress-shear rate relationship, effective and plastic viscosities, yield strength and gel
strength. The properties were determined under high temperature and pressure by using a flow
loop, the Baroid roller oven and the FANN-70 viscometer. The corrosion measurements were
carried out by weight loss and electrochemical techniques. The effective and plastic viscosities of
the drilling fluid decrease with increase in temperature and increase in time of exposure to
downhole conditions. The corrosion rate of 1018 mild steel will increase with a decrease in the
pH of the fluid. The corrosion rates are lower at the mildly alkaline pH and higher in the mildly
acidic pH range. The drilling fluid generally attacks the grain boundaries of the steel samples.
Diffusion was found to be the rate limiting step for the corrosion reactions.
S.Salimi et al [5] conducted a research on the rheological behavior of polymer-extended waterbased drilling muds at high temperatures and high pressures simulating their true working
conditions in a deep oil well. The performance of these polymers as a rheology modifier in
drilling systems was then investigated using a Fann 50C commercial viscometer. By measuring
shear stress vs. shear rate (i.e., the flow curve) at pressures up to 500 psi and temperatures up to
300°F , it was found that temperature had a detrimental effect on the rheological properties of the
test fluids while the effect of pressure on these properties was realized to be less significant
(specially at pressure above 300 psi).
Osman and Aggour [6] carried out an experiment to determine drilling mud density change
with pressure and temperature using a newly developed Artificial Neural Networks (ANN)
model. Available experimental measurements of water-base and oil-base drilling fluids at
pressures ranging from 0 to 1400 psi and temperatures up to 400 °F were used to develop and
test the ANN model. With the knowledge of the drilling mud type (water-base, or oil-base) and
its density at standard conditions (0 psi and 70°F) the developed model provides predictions of
the density at any temperature and pressure (within the ranges studied) with an average absolute
percent error of 0.367, a root mean squared error of 0.0056 and a correlation coefficient of
0.9998.
Ran Qi (2009) [7] research into CO2transport in aquifer and applied it to optimize CO2 storage
in aquifer and oil reservoirs. Jens T. Birkholzer et al (2008) carried out research on the largescale impact of CO2 storage in deep saline aquifers with the main objective on investigation of
the three dimensional region of influence during/after injection of CO2 and evaluating the
possible implications for shallow groundwater resources.
Jennie C. Stephens (2008) [8] considered the geochemical reactions that enhance
transformation of CO2gas into dissolved or solid phase carbon. This involves liberation of
cations to neutralize carbonic acid. They carried out the assessment of potentials and limitations
of various geochemical techniques. CO2 flooding in practice usually involve alternating CO2
injection and water injection.
2.0 METHODOLOGY
2.1 APPARATUS USED
The experimental apparatus used in this study consists of a Fann Model 800 HighTemperature,
High Pressure (HTHP) Viscometer, the Hamilton beach mixer, the hot plate, stirrer, API filter
press, pH meter and the mud balance.
2.2 MUD PROPERTIES
SAMPLE A
Laboratory temperature = 29.5oC
Volume of water = 350ml
Mass of Bentonite = 12.5grams
Mass of NaCl = 1grams
Mass of Barite = 145grams
2.3 PROCEDURES
The procedures followed in the course of this research are thus:
1. A water-based mud of 10.6ppg was prepared.
2. Initial properties of the mud were measured such as the density, shear stress, yield point,
resistivity and acidity. From this the apparent and plastic viscosity were calculated.
3. Mud sample was placed in a modified filter press to serve as a high pressure vessel in form of
a closed system.
4. CO2 gas was injected into the mud sample at an average pressure of 900psi and temperature of
29.50C. Injection was daily after the first injection of 3days.
5. Just before the injections the following measurements were carried out:
The shear stress and gel strength of the mud were measured with rotary viscometer. The
viscosity of the mud was then calculated from the measured properties. Also, the resistivity of
the mud and pH of the mud was measured.
3.0 RESULTS AND ANALYSIS
Details of the experiments are tabulated below. The values of plastic, apparent viscosities, yield
points, shear stresses, pH, density and resistivity are represented in the table. The values
obtained, are a function of aging and temperature.
Table 3.1 shows the effect of aging on the rheological properties of water based mud
Shear Stress
Temperature( 600 RPM 300 RPM PV(Cp)
O
C)
Days
0
3
4
4
6
7
8
9
10
11
12
13
29.5
29.5
29.5
29.5
29.5
29.5
29.5
29.5
29.5
29.5
29.5
29.5
52
50
48
45
43
41
40
39
38
37
36
34
46
45
43
40
38
37
36
35
34
34
33
31
AP(Cp)
6
5
5
5
5
4
4
4
4
3
3
3
26
25
24
22.5
21.5
20.5
20
19.5
19
18.5
18
17
YP(lb/1000ft)
40
40
38
35
34
32
32
31
31
30
29
28
Table 3.2 shows the effect of temperature and aging of the rheological properties of water
based drilling fluid
o
Days
1
2
3
4
5
6
7
8
9
o
o
o
40 C
50 C
60 C
70 C
600RPM 300RPM 600RPM 300RPM 600RPM 300RPM 600RPM 300RPM
45
35
42
33
40
30
38
28
43
33
40
30
38
28
35
25
42
30
38
28
36
25
33
23
40
28
36
27
34
22
31
21
38
26
34
25
32
20
29
18
36
25
32
23.5
30
19
27
16
34
23
30
21
28
18
25
15
32
22
28
20
25
17
23
13
30
20
25
18
22
15
20
12
Figure 1 shows Shear stresses as a function of aging
Graph of Shear Stress Against Time
60
50
Shear Stress
40
30
600 RPM
300 RPM
20
10
0
0
5
10
Time, Days
15
Figure 2 shows Plastic, Apparent viscosities and yield point as a function of aging
Graph of Viscosity Against Time
45
40
35
Viscosity,Cp
30
PV
25
AV
20
YP
15
10
5
0
0
2
4
6
8
Time, Days
10
12
14
Figure 3 and 4 shows the effect of temperature and aging on water based drilling fluid
Graph of Shear stress(300 RPM) Against Time
40
35
Shear Stress
30
25
40 deg
50 deg
20
60 deg
70 deg
15
10
5
0
0
2
4
Time,Days
6
8
10
Figure 4
Graph of Shear Stress(600 RPM) Against Time
50
45
40
Shear,Stress
35
40 deg
30
50 deg
25
60deg
20
70 deg
15
10
5
0
0
2
4 Time, Days 6
8
10
Table 3.3 shows the Viscosity, Density, hydrogen ion concentration and resistivity for a
CO2 contaminated mud as a function of aging
Shear Stress
Density
Temperat
O
Days ure( C) 600 RPM 300 RPM PV(Cp) YP(Cp) AV(Cp)
0
29.5
52
45
7
38
26
3
29.5
45
36
9
27
22.5
4
29.5
30
21
9
12
15
4
29.5
28
19
9
10
14
6
29.5
24
16
8
8
12
7
29.5
20
12
8
4
10
8
29.5
18
10
8
2
9
9
29.5
16
10
6
4
8
10
29.5
15
9
6
3
7.5
11
29.5
14
9
5
4
7
12
29.5
13
8
5
3
6.5
13
29.5
13
8
5
3
6.5
`
ph
9.52
8.13
7.22
6.98
6.78
6.5
6
5.89
5.8
5.65
5.6
5
ppg
10.6
10.4
10
9.8
9.5
9
8.9
8.8
8.75
8.7
8.7
8.7
3
lb/ft
79
78
75
74.5
72
67.5
66.5
66
65.5
65
65
65
S.G Resistivity (ῼ)
1.27
0.35
1.25
0.36
1.2
0.37
1.19
0.4
1.14
0.43
1.08
0.45
1.07
0.5
1.06
0.53
1.05
0.55
1.04
0.58
1.04
0.6
1.04
0.6
Figure 5, shows resistivity variation with time after CO2 contamination
Graph of Resistivity Against Time
0.7
Resistivity,ῼ
0.6
0.5
0.4
0.3
Resistivity
0.2
0.1
0
0
2
4
6
8
10
12
14
Time, Days
Figure 6 shows Viscosity variation with time after CO2 contamination
Graph of Viscosity Against Time
40
35
Viscosity,Cp
30
25
PV,(Cp)
20
AV,(Cp)
15
YP,(lb/1000ft)
10
5
0
0
2
4
6
8
Time, Days
10
12
14
Figure 7 shows hydrogen ion concentration variation with time after CO2 contamination
Graph of pH Against Time
10
9
8
7
pH
6
5
4
pH
3
2
1
0
0
2
4
6
8
10
12
14
Time, Days
Figure 8 shows shear stress variation with time after CO2 contamination
Graph of Shear Stress Against Time
60
50
Shear Stress
40
600 RPM
30
300 RPM
20
10
0
0
2
4
6
8
Time,Days
10
12
14
Figure 9 shows Density variation after CO2 contamination
Graph of Density Against Time
90
80
70
Density
60
50
Density(ppg)
40
Density(S.G)
30
Density(lb/ft3)
20
10
0
0
5
Time, Days
10
15
Table 3.4 shows the Shear Stress of the mud after CO2 contamination mud as a function of
temperature and time
Days
1
2
3
4
5
6
7
8
9
10
40oC
50oC
60oC
70oC
600RPM 300RPM 600RPM 300RPM 600RPM 300RPM 600RPM 300RPM
45
35
42
33
40
30
38
28
40
25
38
23
35
20
33
18
30
20
28
18
25
15
23
13
25
16
23
15
20
13
19
11
20
14
19
11
16
10
14
9
18
12
15
9
13
8
10
7
15
8
9
7
8
6
7
5
10
6
7
4
6
3
5
2.5
8
4
6
3
5
2.5
4
2
5.5
3
4
2
3
2
2
1
ANALYSIS OF RESULT
Effect of temperature
The effect of temperature on water based drilling mud can be as a result of the interplay of
various factors, some of these factors are more pre-dominant than others. These factors include;
reduction in the degree of hydration of the counterions, reduction of the viscosity of the
suspending medium, increased dispersion of associated clay micelles, changes in the electrical
double layer thickness and increased thermal energy of the clay micelles. Since all these
processes take place in the drilling fluid simultaneously as the temperature changes, therefore an
interpretation of the observed results would be possible in cases whereby some of the effects are
predominant and as such be easily identified.
As shown in figures3 and 4, shear stress decrease steadily with increase in temperature for all
values of aging time.
Aging effect
The effect of aging on mud rheology was also studied. The results are shown in figure 1 and 2. it
was observed that viscosity at a given temperature decreases with increase in aging time and the
aging effect are diminishing as the aging time increases especially for the yield point. The
reason for this decrease in viscosity may be gotten from an analysis of the composition of the
drilling fluid formulated for this study. Salt (NaCl) was added to maximize gel strength and also
for compatibility against salt formations. Moreover, salt from its chemical properties is known to
have a high water retention capacity which increases with exposure time (i.e.aging). This can
even be physically observed when a sample of sodium chloride salt is exposed to the air; the salt
becomes moist after some time. it can be thus be deduced that there is an increase in moisture
content as a result of the absorption of water molecules from the surrounding by the salt
molecules as aging time increased which therefore results in a decrease in viscosity.
Effect of CO2 gas kick on resistivity
As shown in figure 5, resistivity increase with increase in CO2 gas contamination.
Effect of CO2 gas kick on viscosity
From figure 6, it was discovered that viscosity decreases with increasing CO2 gas contamination
Effect of CO2 gas kick on pH
As shown in figure 7, it shows that pH decreases with an increasing amount of CO 2
contamination.
Effect of CO2 gas kick on density
As shown in figure 9, it shows that density decreases with increase in CO2 gas contamination
CONCLUSION
It is has been established that temperature and aging have effects on the drilling fluid properties.
It was also discovered from this research that viscosity, yield point, gel strength and shear stress
at a given shear rate decrease with increase in temperature and aging time. Challenges in drilling
operation can be avoided if the optimum values of these properties are maintained.
RECOMMENDATION
Further research work should be carried out to prevent or minimized the effect of CO2 gas on
water based drilling fluid.
REFERENCES
1. Annis, M.R. 1997. Retention of synthetic-based drilling material on cuttings discharged
to the Gulf of Mexico. Report for the American Petroleum Institute (API) ad hoc
Retention on Cuttings Work Group under the API Production Effluent Guidelines Task
Force. American Petroleum Institute, Washington, DC. August 29, 1997.
2. Alderman, N. J., Gavignet, D. and Maitland, G. C., "High Temperature, High Pressure
Rheology of Water-Based Muds" SPE18035, Symposium, Oct. 2 – 5, 1988, pp187-195
3. Mohammed Shahjahan Ali (M.Sc. Thesis, June 1990): "The Effects of High Temperature
and Aging on Water – Based Drilling Fluids." King Fahd University, Dhahran, Saudi
Arabia
4. Shokoya O.S., Ashiru O. A. And Al-Marhoun M. A. 1997. The Rheology and corrosivity
of water-base drilling fluid under simulated downhole conditions. King Fhad University
of Petroleum and Minerals, P.O. Box 589, Dhahran 31261 (Saudi Arabia)
5. Salimi, S., Sadeghy, K., Kharandish, M.G., "Rheological Behaviour of PolymerExtended Water-Based Drilling Muds at High Pressures and Temperatures", University
of Tehran, Iran, pp. 1-6.
6. Osman, E.A. and Aggour, M.A.: "Determination of Drilling Mud Density Change with
Pressure and Temperature Made Simple and Accurate by ANN", Paper SPE 81422,
Presented at the 2003 SPE Middle East Oil Show and Conference, Bahrain, 5 -8 April.
F.A.Makinde et al./Petroleum&Coal 53(3) 167-182, 2011 173
7. Ran Qi, (2009) Simulation of Geological Carbon Dioxide Storage, Ph.D. dissertation,
Department of Earth Science and Engineering, Imperial College London, UK .
8. Jennie C. Stephens and David W. Keith , June 2008, Assessing geochemical carbon
management, Springer on line publications, (http://www.clarku.edu /faculty/jstephens/
documents/)
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