SPE-192198-MS
Prevention of Barite Sagging while Drilling High-Pressure High-Temperature
(HPHT) Wells
Salem Basfar, Salaheldin Elkatatny, Mohamed Mahmoud, Muhammad Shahzad Kamal, and Mobeen Murtaza, King
Fahd University of Petroleum and Minerals, Theo Stanitzek, Akzo Nobel Chemicals AG.
Copyright 2018, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Kingdom of Saudi Arabia Annual Technical Symposium and Exhibition held in Dammam, Saudi Arabia, 23–26
April 2018.
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Abstract
Barite sagging is one of the common issues while drilling high pressure-high temperature wells. This
will cause variation in the mud weight in both vertical and deviated wells. Barite sagging can cause many
problems such as; density variations, well-control problems, stuck pipe, downhole mud losses, and
induced wellbore instability.
The objective of this study is to assess the effect of adding a new copolymer to the invert emulsion
drilling fluid to prevent the sagging issue. Sag test was conducted under static conditions over a wide
range of temperature (200°F to 350°F). Sag test was performed using vertical and decline (45° degree)
aging cell. In addition, the effect of adding the new copolymer on the rheological properties and the
electrical stability of the invert emulsion drilling fluid was evaluated.
The results obtained showed that adding 1 lbm/bbl of the new copolymer had no effect on drilling fluid
density (14.5 ppg). The new copolymer slightly enhanced the electrical stability of the invert emulsion
drilling mud. The new copolymer had a minor effect on the plastic viscosity, yield point, and gel strength.
Adding 1 lbm/bbl of the copolymer prevent barite sagging at 350°F, where the sag factor was 0.55 before
adding copolymer, and 0.503 after adding it. The storage modulus (G') was increased by 40% after adding
1 lbm/bbl of the new copolymer confirming the sag test results. There was no effect of adding the new
copolymer in the filtration loss and filter cake thickness.
The novelty of this work is the development of a new drilling fluid formulation that can be used in
drilling HPHT wells without any sag issue. This development will help the drilling engineers to safely
drill deep wells and maintain the drilling fluid integrity during the drilling operation. In general, this will
reduce the overall cost of the drilling operation by reducing the non-productive time in solving many
issues such as well control, loss of circulation, or pipe sticking.
Introduction
Oil or gas wells which have static reservoir (Fig. 1) pressure greater than 10000 psi and temperature
above 300°F are classified as high-pressure high-temperature (HPHT) wells (Smithson T., 2016).
Completion of HPHT wells are one of the most challenging in the oil industry. This complexity in HPHT
well pushed the researchers to develop a formulation of drilling fluids that can be used to control the
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formation pressure and provide a well control. Barite as a weighting material was used to increase the
drilling fluid density. The main issue of barite is the settling of its particles (Aldea et al. 2001; Meeten
2001; XIAO 2013).
During break in drilling operation, it is common to put the drill pipe under low rotation to avoid pipe
stuck. This low rotation causes break in drilling fluid and accelerates settling of barite which will give
sever barite sag (Bern et al. 2000). Barite sag is generally defined as settling of weighting materials in
drilling fluid. Sag is often seen when the driller circulating the mud out of the hole after the mud stayed
for some time in the well, leading to the confidence that the static settling of mud is the main indicator to
give barite sag (Hanson et al. 1990).
(Nguyen et al. 2011, 2014) studied the parameter that effect dynamic barite sag. These parameters are
annular velocity, pipe rotation, inclined angle, and eccentricity. Two scales were used for each parameter.
They found that under the static condition when yields stress greater than 12 lbm/100 ft2, no sag occurs.
They also showed the modified rotational viscometer (MRV) can be used for predicting barite sag
potential, but it doesn’t correlate flow loop. Moreover, they showed that annular velocity and pipe rotation
provide nearly 60% and 21% individually to prevent sag. By flow loop, they observed that even when
annular velocity is low, pipe rotation can control barite sag. (Bern 2000; Dye et al. 2006) studied the effect
of annular velocity on barite sag, they found that annular velocity closed to 30 ft/min induce barite sag.
(Bui et al. 2012; Saasen et al. 1995) mentioned that fluids that have weak gel structure have rapidly
sagged. Initial high gel strength can be reduced significantly when it exposes to low shearing resulting in
dynamic sag. Also, they pointed out G’/G” can indicate sag potential. (Dye et al. 1999, 2006) have given
the following conclusion of dynamic sag: At shear rate less than 4 s-1, dynamic sag occurs in inclined
wells. They also showed that as well angle increase from 45° to 60° barite sag have increased. Moreover,
when annular velocity goes as high as 100 ft/min dynamic barite sag is low. Finally, they came up with 6speed viscometer can’t correlate dynamic barite sag.
(Wagle et al. 2013, 2015) used suspension agent and nanoparticles with rheological modifiers to
minimize sag in free organoclay invert emulsion mud for both vertical and 45° conditions. The result
showed that invert emulsion drilling fluids (IEFs) formulated with nanoparticles and rheology modifiers
(RM) were stable at 250°F and 300°F. also, IEFs with nanoparticles and RM exhibit no sag tendency for
9, 12 and 16 ppg mud density for both vertical and 45° deviated tests. In addition, HPHT rheology of IEFs
showed consistency before and after adding nanoparticles. Sag occurrence in vertical and deviated wells
particularly with angle between 30° -75° (Amighi and Shahbazi 2010; Bern et al. 1996; Hanson 1990;
Jefferson 1991).
(Elkatatny & Nasr El-Din 2012) used ilmenite 5 µm weighting materials instead of barite to enhance
the properties of WBM. They found that ilmenite improved the zeta potential and filtration volume with
not much increase in the viscosity. For the sag test, no dynamic sag was shown when ilmenite was used.
(Al-bagoury 2014) investigated micronized ilmenite as a weighting martial in both oil-based mud
(OBM) and water-based mud (WBM). The result showed that micronized ilmenite reduced dynamic sag
better than API barite. Also, it doesn’t effect on rheology and HPHT filtration. Micronized barite was
evaluated by (Mohamed et al. 2017) to enhance the properties of WBM. The result showed that micronized
barite has given an insignificant improvement in sag performance.
In this paper, a new copolymer, which can be considered as a sag resistance of IEFs weighted by barite
at 14.5 ppg mud density was used. Both of static and dynamic conditions were applied. The static case
was tested in vertical and 45° case. The rheological properties of IEFs were measured before and after
copolymer have been added. HPHT Filtration and electric stability of IEFs were evaluated.
SPE-192198-MS
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Barite Sag Evaluation
Static Sag
Static sag is often used to know the ability of a drilling fluid to suspend weighting material at specific
temperature and time in a static condition. The Sag performance of the mud was evaluated by
determination of sag factor. Sag factor bigger than 0.53 implies that the drilling fluid has the possibility
to settle weighting material downward of mud (Maxey 2007).
Viscometer Sag Test
The Viscometer Sag Test (VST) introduced by (Jefferson 1991) as a feasible wellsite test, it has a
practical applications in the field and in the laboratory as a straightforward indicator of sag tendencies.
Simplicity, low-cost, and equipment availability nevertheless, the VST has not received sufficient industry
support to become API standard.
Viscometer Sag Shoe Test (VSST)
(Zamora and Bell 2004) used VST but they added sag shoe. This low-cost modification was developed
to improve the consistency, sensitivity, and accuracy of the standard VST. The improved design can also
characterize the sagging bed to help determine the best course of action to correct a sag problem in the
field. Like the original VST, the recent version can also be used in the laboratory for evaluating the sagtolerance of mud systems and products. The VSST was designed around the 6-speed rotational viscometer
and thermocup used routinely to measure mud rheological properties. The viscometer provides the
consistent (though somewhat complex) shear to simulate dynamic conditions; the thermocup serves as the
mud container and heats the mud to 180°F maximum (although the test normally run at 120 °F or 150°F)
(Bern et al. 2010).
Flow Loop Test
Flow loop experiments can simulate field environments such as hole angle, eccentricity, and annular
flow. Flow loop test assists as the guide for recognizing dynamic sag at laboratory conditions. The flow
loop device has been used to examine the connection between shear rate and dynamic sag using invert
emulsion drilling fluid systems in a declined, eccentric annulus (Bern 1996; Dye et al. 2001).
Fig. 1‫ ــــ‬HPHT regions (Smithson 2016)
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Experiments and Materials
Materials
In this paper, invert emulsion drilling fluids were manually prepared in the lab. The formulas were
taken from the real field and published works (Temple et al. 2005). In order to investigate the effect of
adding copolymer on the IEFs, it was essential to keep the copolymer as low as possible to avoid any
removal problems and also to reduce the overall cost of the drilling fluids. The density of the drilling fluids
used in this work was 14.5 ppg and had an oil-water ratio of 80:20. The type of drilling fluid in this work
is inverted emulsion oil-based mud. The composition and properties of drilling fluids are given in (Table
1)
Table 1— Recipe of 14.7 ppg Invert Emulsion Drilling Fluid
Additives
Diesel
Primary Emulsifier
Lime
Filtration control
Water
CaCl2
OBM Viscofier
Secondary Emulsifier
Copolymer
Bridging Agent
Weighting agent
Unit
bbl
ppb
ppb
ppb
bbl
ppb
ppb
ppb
ppb
ppb
ppb
Quantity
0.491
11
6
7
0.143
32
10
4
1
30
300
Experimental Work
Static Sag
A static sag in drilling fluid was measured at the static environment to know either mud is stable or
fluctuated in density. Sag factor was calculated by equation (1):
𝑆𝑆𝑆𝑆 =
𝜌𝜌𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏
… … … … … … . . (1)
𝜌𝜌𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏 +𝜌𝜌𝑡𝑡𝑡𝑡𝑡𝑡
Where, SF is static sag factor, 𝜌𝜌𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏𝑏 and 𝜌𝜌𝑡𝑡𝑡𝑡𝑡𝑡 are density of the mud from lower and upper part,
respectively.
If the sag factor showed in equation (1) is higher than 0.53, the weighting material settles down from
drilling fluid, (Maxey 2007). The aging cell (Fig. 2) was used to construct sag performance for both
vertical and 45° tests. Drilling mud is mixed for15 min by a high-speed mixture. Then, fluid is pressurized
in the aging cell up to 400-500 psi to prevent evaporation. After that, the cell is heated to the desired
temperature and angled for 24 hrs. Finally, 10 ml fluid should be drowned and recorded the weight then
apply the equation to calculate sag factor.
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Fig. 2— HPHT 45° setup aging cell
Dynamic sag
The viscometer sag shoe test (VSST) is a well site and laboratory test to perform weight-material sag
tendency of a field and lab-prepared drilling fluids under dynamic conditions (Zamora and Bell, 2004).
The idea is that the sloping surface of the thermoplastic shoe helps to accelerate settling and to concentrate
the weighting material into a single collection well at the bottom of the thermos-cup as shown in (Fig. 3).
(Zamora 2004) recommended the following procedure for the sag test:
• Sag shoe is inserted into thermocup and both are put on the plate of the viscometer.
• Poured the mud inside thermocup and rise it until the upper surface touches the lower part of
viscometer sleeve. Then lower themocup around 7 mm.
• Heat the 140 ml mud with sag shoe to 120°F ±2°F error.
• Set the viscometer at 100 RPM and start 30 min timer
• Using the syringe with the cannula attached and clear of air extract a 10 ml sample and record the
weight of the mud filled syringe, W1
• Stop the viscometer after 30 min and take another sample of 10 ml
• Record the weight of the mud filled syringe(W2)
• Calculate the VSST using equation (2)
VSST = 0.833 x (W2-W1) ………………………………….. (2)
where
VSST = viscometer sag shoe test, ppg
It appears that a VSST value of 1.0 ppg or less would imply a drilling fluid with the minimal sagging
tendency, (Aldea 2001). A VSST value above about 1.6 ppg would indicate the beginning of a possible
sag problem (Bern et al. 2010)
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Fig. 3— Basic equipment for VSST excluding the viscometer
Rheology
The rheological properties of IEFs were characterized in term of plastic viscosity (PV), yield point
(YP), 10 sec gel strength, and 10 min gel strength. The viscoelastic properties of IEFs were determined
by Anton Paar 302 Rheometer. Oscillation amplitude test is firstly applied to determine linear viscoelastic
(LVE) by keeping the frequency constant and free amplitude increase with time. After LVE rang is
determined, the oscillation frequency is applied by letting frequency free and constant amplitude. The
objective of this test is to investigate time-dependent viscoelastic properties. Elastic modulus G' and
viscous modulus G" are gotten from oscillation frequency test. G' has a good relation with sag (Maxey
2007)
HPHT Filtration
HPHT filtration tests were performed using HPHT filter press at 300°F and 400 psi. The tests were run
for 30 minutes. For the tests, ceramic disks saturated for 24 hrs. in diesel with mean pore diameters of 50
μm were used. A mud is filtrated before and after copolymer was added.
Result and Discussion
The Effect of Copolymer on Static and Dynamic Sag
Vertical and 45°static Sag factor of values for 14.5 ppg mud samples after aging for 24 hrs. are
illustrated in (Fig. 4) and (Fig. 5) respectively. The data indicates that using copolymer in the internal
phase provides best sag stability at higher temperatures for both vertical and 45°.
The sag factor of tested IEFs before adding copolymer is 0.55 at the vertical condition and 0.6 at the
deviated test, which indicates a potential of sag. Sag factor values of IEFs after adding copolymer indicate
SPE-192198-MS
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lower sag tendencies of samples tested started from 250°F to 350°F. This is mainly due to the sagresistance of copolymer particles, which provides a more stable suspension. The VSST scheme gives a
value that is the density difference, in lbm/gal, between the sagged, dense drilling fluid that has settled to
the bottom of the cup, and the base drilling fluid.(Fig. 6) shows the difference between W1 and W2 of base
about 1.4 ppg and for copolymer about 0.5 ppg in 30 min.
The significantly better sag stability using copolymer can be due to effective dispersion of particles in
invert emulsion fluid which providing a more stable suspension.
Fig. 4— vertical sag factor at the different temperature
Fig. 5— 45° sag factor at the different temperature
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Fig. 6— Viscometer sag shoe test at 120°F
Effect of the Copolymer on Rheology and Electric Stability
Table 2 and (Fig. 7) shows the rheological properties of mud before and after adding copolymer. It was
found that copolymer didn’t effect plastic viscosity which is 34 cP and 39 cP before and after adding
copolymer, respectively.
Table 2— Rheological properties before and after adding 1lb/bbl copolymer at 300 °F for 14.5 ppg drilling fluid
Property
IEF before adding the
copolymer
IEF after adding the
copolymer
R600
115
135
R300
81
96
R200
68
81
R100
54
64
R60
47
56
R30
41
49
R6
34
40
R3
34
37
PV (cp)
34
39
YP (lb/100ft2)
47
57
10 sec. Gel Strength,
(lb/100ft2)
10 min Gel Strength,
(lb/100ft2)
30
41
30
45
Adding the copolymer can assist form more stable emulsions and improve the rheological properties
of drilling muds as shown clearly in 10 sec. and 10 min. gel strength.
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Fig. 7— The effect of the copolymer on mud Rheology at 300°F
Amplitude sweep test was conducted first to know the LVE region of mud to see the structural
properties of liquids. The results from the amplitude sweep test are presented in (Fig. 8). Result shows
that LVE was upto about 0.2 %. For this mud, the storage modulus was higher than loss modulus. This
means that mud sample exhibits a character of elastic behavior so, the mud is showing gel structure.
Frequency sweep test was used to measure the response of fluid to deform in time-dependent behavior.
(Fig. 9) shows storage modulus of a new formulation is 40% greater than base mud. This means that new
formulation is more stable and can resist sagging.
Fig. 8— Amplitude sweep test performed on OBM-base at 300°F
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Fig. 9— Storage modulus, G’ of IEF at 120°F at Shear Strain = 0.2%
Electrical stability is measuring voltage required to induce a current through the sample. (Fig. 10)
shows as copolymer were added the electrical stability increased. This means that the stronger the
emulsion, the higher the voltage required to produce emulsion breakdown for circuit completion, the
higher stability of fluid.
Fig. 10— Electrical stability of OBM at 120F
Effect of Copolymer HPHT Filtration
(Fig. 11) illustrates the HPHT filtration rates of base mud and mud with the copolymer (mud5) at
200°F and 400 psi. The copolymer has reduced the filtration from 2.6 cm3 to 2.1cm3, (Fig. 11). The
copolymer reduced the invasion volume about 20% which reduce the formation damage. For filter cake
thickness, both of base mud and mud5 showed thin cake 1.4 mm and 1.45 mm, respectively.
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Fig. 11— The effect of adding copolymer on HPHT filtration
Summary and Conclusions
Drilling fluid properties were measured for an invert emulsion drilling fluid, which confirmed the
presence of sag issue (barite settling). A new copolymer was added with a concentration of 1 lbm/bbl to
the invert emulsion drilling fluid. The properties were measured again, and the following conclusion can
be drawn:
– Adding 1 lbm/bbl l of the new copolymer had no effect on drilling fluid density (14.5 ppg).
– The new copolymer enhanced the electrical stability of the invert emulsion drilling fluid.
– The new copolymer had a minor effect on the plastic viscosity, yield point, and gel strength.
– Adding 1 lbm/bbl of the copolymer prevent barite sagging at 350°F, where the sag factor was
0.504.
– The storage modulus (G') was increased by 40% after adding 1 lbm/bbl of the new copolymer
confirming the sag test results. There was no effect of adding the new copolymer in the filtration
loss and filter cake thickness.
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