Experimental analysis of calcium carbonate scale formation and inhibition in waterflooding of carbonate reservoirs

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Author’s Accepted Manuscript
Experimental analysis of calcium carbonate scale
formation and inhibition in waterflooding of
carbonate reservoirs
Azizollah Khormali, Dmitry G. Petrakov,
Mohammad Javad Afshari Moein
PII: S0920-4105(16)30510-1
DOI: http://dx.doi.org/10.1016/j.petrol.2016.09.048
Reference: PETROL3655
To appear in: Journal of Petroleum Science and Engineering
Received date: 18 June 2016
Accepted date: 27 September 2016
Cite this article as: Azizollah Khormali, Dmitry G. Petrakov and Mohammad
Javad Afshari Moein, Experimental analysis of calcium carbonate scale formation
and inhibition in waterflooding of carbonate reservoirs, Journal of Petroleum
Science and Engineering, http://dx.doi.org/10.1016/j.petrol.2016.09.048
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1
Experimental analysis of calcium carbonate scale formation and inhibition in
waterflooding of carbonate reservoirs
Azizollah Khormali1, Dmitry G. Petrakov1, Mohammad Javad Afshari Moein2
1Department of Oil and Gas Field Development and Operation, Oil and Gas Faculty, Saint Petersburg Mining
University, Saint Petersburg, Russia, 199106
2Geological Institute, ETH Zurich, Switzerland
Abstract
Deposition of inorganic salts such as calcium carbonate (CaCO3) can cause formation
damage and production equipment failure during the development of a reservoir. In case of
waterflooding, complex geochemical processes between the injection water, formation water and
rock occur and the concentration of ions increases. Major contribution of scale control
concentrates on understating the conditions scale formation and its inhibition.
In this paper, we analyze experimentally the effect of oil composition and flow conditions
on CaCO3 scale formation. We measured the induction period of CaCO3 crystallization in a
stirred vessel with different Reynold numbers and the interfacial tension at the boundary between
the aqueous scale inhibitor and oil at different percentages of organic components. In addition,
we determined the performance of CaCO3 scale inhibition under different static and dynamic
conditions in some Iranian carbonate core samples.
The experimental results showed that if the interfacial tension was reduced by increasing
the concentration of organic components to 1.5 percent, the CaCO3 precipitation decreases more
than 30 percent. In addition, increasing the flow velocity (Reynolds number) had a great
influence on the increase in the induction period of CaCO3 crystallization. However, the
induction period was insignificantly changed at higher values.
Using a recently developed scale inhibitor, we kept the CaCO3 formation at a constant
concentration of 30 mg/L. The efficiency of the inhibitor was insignificantly reduced if the

2
temperature is increased up to 120 ºC. Core flooding experiments show that formation damage
due to CaCO3 precipitation depends on the injection rate of the solution. In addition, the
formation damage was mitigated to the 93 % of initial permeability of the core samples. The
results of this work improve our understanding from CaCO3 formation and can be used to predict
and prevent it during waterflooding process in carbonate reservoirs.
Keywords: Calcium carbonate; formation damage; induction time; Reynolds number; scale
inhibitor; waterflooding
1. Introduction
Inorganic salt precipitation can occur during the fluid flow in reservoir and wellbore as
well as the wellhead in petroleum operations. Salt deposition could have extremely undesirable
consequences such as reduction of production rate, well productivity and the turnaround time of
electrical submersible pumps, as well as plugging the perforations, premature failure of
downhole equipment and formation damage (Naseri et al., 2015; Yi et al., 2014). These
phenomena could result in a significant deterioration of development process. The control of the
inorganic salt formation is complicated due to the complex reservoir fluid composition (Kelland,
2014). Calcium sulfate, calcium carbonate, barium sulfate and magnesium carbonate are the
most common types of inorganic salts deposited in oil and gas industry.
A water system with a high concentration of salt-forming ions is essential for precipitation.
Different conditions and parameters affect CaCO3 deposition during the oilfield operations.
CaCO3 precipitation can be determined by the loss of chemical equilibrium between ions, and
carbon dioxide (CO2) in water (Aziz et al., 2011). The CO2 balance determines the possibility of
CaCO3 precipitation. When the pressure is below the saturation pressure, gas releases from the

3
liquid primarily in the reservoir and on the walls of the production equipment (MacAdam and
Parsons, 2004). Therefore, multiple interfaces are formed in phase separation. This condition is
favorable for the nucleation and crystal growth of CaCO3. Salt deposits can also serve as
adsorbents to the heavy components of the reservoir fluid and result in adhesion of solid particles
to gas bubbles (Chibowski et al., 2003; Abdel-Aal et al., 2002).
Prediction of scale formation during the oil production is of great practical importance.
Previous studies have been able to qualitatively predict the salt formation and scaling intensity
(Amiri et al., 2013). In addition, mathematical models can be used to predict the possibility of
inorganic salt deposition in porous media (Shokrollahi et al., 2015). CaCO3 scale prediction
during weterflooding is based on processes that contribute to the precipitation of inorganic salts
(minerals) from aqueous solutions (Ramstad et al., 2005). These processes consist of mixing
incompatible mobile water with oil, decomposition of calcium bicarbonate as a result of changes
in physical and chemical conditions of the reservoir, and change of CaCO3 solubility in water
with a pressure drop (Mackay and Jordan, 2005). The formed salt can be precipitated, if it has
sufficient concentration. In this case, metastable and unstable regions are obtained to determine
the salt precipitation. Boundary of these regions depends on temperature and ion content of the
solution (Steiger, 2005).
CaCO3 solubility in water greatly depends on the content of CO2, which is in dynamic
equilibrium with certain proportions of bicarbonate (HCO3-) and carbonate (CO32-). It is a
difficult task to determine the CO2 content in the highly mineralized water. However, the
quantitative relation between СО2, НСО3- and СО32- (carbonate equilibrium) can be determined
by the concentration of hydrogen ions. Wherein, pH, which is characterized by the equilibrium
condition between the liquid phase on the one hand, and the solid and gaseous phases on the

4
other hand, is taken into account (Bewernitz et al., 2012; MacAdam and Parsons, 2004). A
forecast of CaCO3 precipitation capabilities is based on a comparison of the actual pH of the
water with the calculated value of pH, when the water is saturated with CaCO3 (Aziz et al.,
2011). Saturation index and scaling tendency is usually taken as an indication of scale formation.
Saturation index only allows qualitatively assessing the ability of the water to precipitate or
dissolve the salt (Moghadasi et al., 2003).
Induction period of salt crystallization is the time of solid phase appearance in a
supersaturated solution with salt-forming ions. Time since the supersaturation of solution with
ions, during which significant changes in the concentration of the solution, and hence deposition
of salt crystals do not occur, is called induction time (Verdoes et al., 1992). Crystallization
process is accompanied by the induction period from the moment of mixing the injection and
formation waters until a visible precipitate. The induction period is reduced with increasing
solution supersaturation. At a certain level of supersaturation, metastable solution is converted
into a labile and unstable solution, from which spontaneous crystallization occurs (Chen et al.,
2005). The induction time of a salt also depends on the presence of other salts and chemical
reagents. This time can be changed with changes in the stirring rate of a solution. Therefore,
mixing intensity of solutions, and flow velocity relative to the solid particles is one of the most
important parameters affecting the crystal growth rate. At a constant temperature and a constant
degree of supersaturation, crystallization rate can vary significantly with changes in flow
velocity (Aziz et al., 2011; Mackay and Jordan, 2005).
Organic components, specifically naphthenic acids and their salts, have a profound
influence on scale formation. Aromatic compounds, unsaturated hydrocarbons, sulfur
compounds, asphaltenes, resins and paraffin are the most common types of organic components,

5
which affect the salt precipitation (Alvarado et al., 2014). The effect of the inorganic components
in CaCO3 scale formation is explained by hydrophobization of the salt crystals due to adsorption
of a water-soluble organic material in porous media, substantially naphthenic acids and their
salts. Adhesion of CaCO3 particles on the walls of downhole tools is described solely by the
hydrophobicity of solid surfaces (Chibowski et al., 2003).
Waterfloodinng is the main method of secondary oil recovery. In this case, complex
geochemical processes of interaction between the injection water and formation water and rock
occur in the reservoir (Naseri et al., 2015; Moghadasi et al., 2004). These processes lead to
formation of saturated solution with ions. Scale formation depends on reservoir temperature,
pressure, level of solution saturation with ions in the mixture of injection and formation waters
and hydrodynamic behavior of fluid flow. These parameters control the amount and morphology
of salt crystals during waterflooding. Therefore, when mixing two incompatible waters with high
concentrations of bicarbonate and calcium ions, CaCO3 crystallization and its precipitation
occurs in the near wellbore formation zones depending on the reservoir pressure and temperature
(Vetter and Farone, 1987).
Rock permeability is reduced due to the scale precipitation during water injection into the
reservoirs. Permeability reduction varies depending upon the injection rate and temperature at a
same initial permeability of the samples (Haghtalab et al., 2015; Moghadasi et al., 2004). The
maximum amount of CaCO3 sediment occurs at higher temperatures because solubility of this
salt is decreased with increasing temperature. Characteristics of salt precipitation influence the
degree of formation damage. Tahmasebi et al. (2010) studied the effect of temperature, salt
concentration, pore volume injected and solution injection rate on the permeability reduction for

6
waterflooding process. Based on laboratory data, they developed a new correlation for the
prediction of the permeability reduction due to the deposition of inorganic salts.
Inhibitor injection into reservoirs is widely used for reservoir and equipment protection
from salt deposits. This treatment provides a reliable long-term protection against scaling
(Khormali et al., 2015; Yan et al., 2015; Verraest et al., 1996). The efficiency of scale prevention
depends on the processes which affect the formation of inorganic salts in the saturated solution
(Liu et al., 2016; Kiaei and Haghtalab, 2014).
Development of new chemical reagents can prevent salt precipitation, if they have high
efficiency and low cost for desired conditions without any adverse effect on the operation, such
as high corrosion rate (Kelland, 2014; Senthilmurugan et al., 2011). Multicomponent and
multifunctional synergistic compositions have been recently studied as potential scale inhibitors
(Gopi et al., 2015). In this experimental study, we have developed a liquid scale inhibitor for
preventing CaCO3 formation, which consists of chemical reagents, including two scale
inhibitors: 1-hydroxyethane 1, 1-diphosphonic acid (HEDP) and polyethylene polyamine-N-
methylphosphonic acid. HEDP forms stable complexes with a large number of cations.
Polyethylene polyamine-N-methylphosphonic acid is anionic inhibitor from the class of organic
phosphates. This inhibitor is highly soluble in water, and insoluble in organic solvents and oil.
The efficiency of the scale inhibitor in the reservoir is determined by its adsorption and
desorption properties and reduction in formation damage due to salt precipitation. The following
factors influence the scale inhibitor effectiveness and its squeeze lifetime: physicochemical
properties of the inhibitor, rock, oil and water, hydrodynamic properties of the reservoir, amount
of injected water and scale inhibitor solution and production rate (Kelland, 2014; Ghosh and Li,
2013).

7
Despite the large effort to forecast and prevent CaCO3 formation, the effect of fluid flow
velocity on precipitation kinetics is poorly understood. In addition, the impact of organic
components of oil on CaCO3 scale formation reservoir conditions requires a detailed analysis. It
is necessary to study the effect of temperature and Ca2+ concentration on the efficiency of scale
inhibitor. In this work, we tried to address these questions by investigating the amount of salt
precipitation in a wide temperature range of 40 to 150 ºC and a pressure range of 0.1 to 60 MPa.
The dependence of the induction period of CaCO3 crystallization on the Reynolds number and
the effect of active organic components CaCO3 precipitation of carbonate core samples were
investigated. In addition, the effect of organic components on the interfacial tension at boundary
between oil and aqueous scale inhibitor solution was studied. Dependence of scale inhibitor
efficiency on reservoir temperature and concentration of calcium ions, as well as dynamic
conditions were investigated using scale inhibitors at different injection rates.
2. Experimental setup
2.1. Determination of scaling tendency and its precipitation
The scaling tendency of a salt formation could be used to predict the possibility of
precipitation depending on the ion content of the solution (in a mixture of injection and
formation waters), temperature and pressure. The scaling tendency of the inorganic salt
formation was determined by the following equation:
sp
KAM
ST ]][[

(1)
where ST is the scaling tendency; [M] and [A] are the concentrations of cation and anion in
mol/L; and Ksp is the solubility product in mol2/L2.

8
Solubility product is a function of temperature, pressure, ion concentration and ionic
strength. The inorganic salt is formed, if scaling tendency value is greater than one. In addition,
saturation index (SI) is defined as the logarithm of scaling tendency. The solution is in saturation
equilibrium condition with CaCO3, if SI=0. When SI is greater than zero, then the salt is
precipitated (Moghadasi et al., 2003). If the saturation index value is negative, the solution can
dissolve the salt.
Characteristics of synthetic formation and injection waters, on which formation and
inhibition efficiency of CaCO3 were investigated, are shown in Table 1. Scaling tendency of
CaCO3 was determined in three different ratios of injection water (IW) and formation water
(FW) (30 % / 70 %, 50 % / 50 %, 70 % / 30 %) using OLI Studio program. The amount of
precipitated salt was determined at different temperatures and pressures. This value could be
determined by the following equation (Amiri et al., 2013):
 
5.02 )4]([][500 sp
KAMAMMWC
(2)
where C is the formed salt concentration in mg/L; MW is the molecular weight of the salt in g/L.
2.2. Induction time of salt crystallization
To determine the induction time of CaCO3 crystallization at different flow rates, the
experiments were carried out using a stirred tank velocities without scale inhibitors. In this case,
the solution of injection and formation waters was mixed in the tank at different stirring rates.
The concentration of calcium ions was measured with time at different rotational speeds.
Beginning of precipitation (induction period for the salt precipitation) was determined by
reducing the initial concentration of cation (Ca2+) with time. In this work, induction period of

9
CaCO3 crystallization was determined at different Reynolds numbers, which depends on
rotational speed of stirred tank. Reynolds number in a stirred tank was defined as follows:


2
Re Nd

(3)
where Re is the Reynolds number; ρ is the density of the solution in kg/m3; N is the rotational
speed in rev/s; d is the agitator diameter in m; and

is the dynamic viscosity of the solution in
Pa.s.
2.3. Interfacial tension measurement
The interfacial tension at the boundary between oil and aqueous scale inhibitor solution at
different concentrations of organic components was determined using an instrument, which is
shown in Fig. 1. Principle of the instrument was based on a system of drop shape analysis for the
measurement of molecular surface properties. The analysis was done according to the shape and
size of the drops. The experiment was performed at atmospheric pressure and room temperature.
Due to the presence of a camera in the instrument, it was possible to measure dynamic contact
angle of drops on the surface. A necessary condition for this was that the drop should be in
hydro-mechanical equilibrium. The camera records the formation of droplets on the surface and
transmits the image to a computer. The program automatically determines the baseline for
calculating the contact angle using several methods. In this work, the solution was a mixture of
the injection and formation waters in a same volume. The concentration of organic components
was increased from zero to 2.5 %.
2.4. Measurement of effectiveness of scale inhibitors under static conditions

10
To prevent CaCO3 scale formation, two different scale inhibitors were used. Chemical
compositions of used scale inhibitors are shown in Table 2. Inhibitor No. 1 is a new developed
scale inhibitor (Khormali and Petrakov, 2016) and inhibitor No. 2 is a widely used scale inhibitor
in oilfields. We performed an experimental investigation on the efficiency of the scale inhibitors
by measuring the concentrations of calcium ions in the solution. The concentration of calcium
ions was measured before and after precipitation of CaCO3 with and without scale inhibitor.
Scale inhibitor efficiency under static conditions (jar test) was calculated by the following
equation (Luo et al., 2015):
%100
][][ ][][
1
2
0
21
2
2
2





CaCa CaCa
E
(4)
where E is the efficiency of scale inhibitor in percentage; [Ca2+]2, [Ca2+]1 and [Ca2+]0 are the
concentrations of calcium ions in the solution after testing with scale inhibitor, without scale
inhibitor and before testing (initial concentration) in mg/L, respectively.
If the scaling inhibition process has an efficiency of more than 90 % in jar test, then the
scale inhibitor is suitable for oilfield applications (Luo et al., 2015). We performed our
experiments in different temperatures and Ca2+ concentrations. The scale inhibitors were tested at
concentrations of 15 and 30 mg/L.
2.5. Core flooding experiments
To study CaCO3 precipitation and its inhibition in the core samples, a core flood apparatus
was used. A schematic diagram of the apparatus is shown in Fig. 2. The apparatus can provide
desired reservoir conditions (pressure and temperature) and different injection rates of the
solution to determine the formation damage due to salt precipitation in the core samples. Three

11
following cases were considered at different solution injection rates: injection of solution into
core samples without inhibitor, using the inhibitors No. 1 and No. 2.
Injection of the solution with and without scale inhibitor was done on carbonate core
samples, the characteristics of which are shown in Table 3. The table presents that the main
content of the core samples was limestone. The solution was a mixture of 50 % of injection water
and 50 % of formation water. The experiments were carried out at a temperature of 80 ºC. The
scale inhibitors were added to the solution at a concentration of 30 mg/L.
To investigate the formation damage due to CaCO3 precipitation, and effectiveness of the
scale inhibitors for preventing the salt formation in the core samples, ratio of core permeability
before and after salt precipitation was determined. In this case, the basic Darcy's equation was
used to obtain the absolute permeability as follows:
PA Lq
K


67.16
(5)
where K the absolute permeability of the core sample in mD; q is the injection rate of the
solution in mL/min;

is the solution viscosity in cp; L is the length of the core sample in cm; A
is the cross sectional areas of the core sample in cm2; and

P is the pressure drop in atm.
3. Results and discussion
3.1. CaCO3 scale formation
3.1.1. Pressure and temperature effects
The prepared synthetic formation water (as shown in Table 1) refers to highly mineralized
and slightly alkaline type of waters, in which CaCO3 can be formed under certain pressure and
temperature conditions. Fig. 3 and Fig.4 present scaling tendency of CaCO3 and its precipitation

12
in three different mixing ratios of IW and FW depending on temperature and pressure. As shown
in Fig. 3 and Fig. 4, CaCO3 scale was formed mainly at low pressures and high temperatures.
Based on chemical composition of the waters and CaCO3 scale tendency, the formation water is
prone to more deposition of CaCO3 in reservoir and oilfield equipment, than injection water, i.e.,
a high tendency of CaCO3 scale formation occurred in lower amounts of injection water in the
mixture with formation.
As shown in Fig. 3 and Fig. 4, by increasing temperature, the possibility of CaCO3
deposition was significantly increased because calcite solubility decreases with increasing
temperature. The effect of the temperature factor can be explained to account for the formation
of carbonate deposits in some deep wells with a high reservoir temperatures. Decrease in
pressure leads to a reduction of the CO2 partial pressure that may be a reason for reducing the
calcite solubility. This is exactly what causes a frequent deposition of calcium in the walls of the
tubing in production wells.
Fig. 5 shows the state diagram of CaCO3 deposition depending on the temperature. As
shown in, four regions of stable, first metastable, second metastable and unstable were
determined depending on the CaCO3 concentration in the solution in a range of temperature
between 60 °C and 150 °C. Fig. 5 displays that in the stable region; the maximum concentration
of CaCO3 was 3.2 mg/L at 105 °C. In the second metastable region, CaCO3 concentration in the
solution was in a range from 2 mg/L to 23.8 mg/L depending on the temperature. The second
metastable region had a larger range of the salt concentration than the first metastable region. If
the salt concentration is more than 24 mg/L at any temperature, the salt is in the unstable region.
3.1.2. Rotational speed effect

13
Effect of stirring speed on the kinetics of CaCO3 crystallization was investigated by
changing the rotation speed of the stirred tank. Fig. 6 presents the results of studies at different
Reynolds numbers. The value of Reynolds number was calculated using Eq. (3). The results
showed that the mixing rate of the solution affects the kinetics of the CaCO3 crystallization to a
certain criterion value of Re. As shown in Fig. 6, induction period was not considerably reduced
for values of Reynolds number more than 6487. Therefore, turbulence of the flow can help
prevent the formation of crystal nuclei under certain conditions. According to the results of the
research, the concentration of calcium at low Reynolds numbers was rapidly decreased, i.e.,
CaCO3 was formed at the least time (low value of the induction period). This demonstrates the
significant role of suspended particles for CaCO3 precipitation at low Reynolds numbers. It
should also be noted that in the system of stirred tank, a flow is in the turbulent regime when
Reynolds number is more than about 10000.
3.2. Organic components in oil
3.2.1. Scale precipitation in presence of organic components
The substantial role of oil components in the scale formation process was confirmed by
conducting experiments of CaCO3 precipitation in the core samples without scale inhibitor. Fig. 7
depicts the results of studies on CaCO3 precipitation in the core samples under dynamic
conditions. The experiments were performed at 80 ºC. As shown in the figure, by increasing the
amount of organic components in the oil, CaCO3 precipitation rate was decreased. At
concentrations of more than 1.5 % of organic components in the oil, decrease in CaCO3
precipitation rate was negligible. Electron microscopic studies of CaCO3 precipitation showed
that the main reason for this was the adsorption of organic components on the surface of the

14
cores, which promote flocculation. The adsorption of polar components on surfaces has acted as
a particle polarization. Therefore, an increase in the particle dispersion in the presence of organic
additives was associated with the adsorption of the organics on the formed particles and
changing the kinetics of CaCO3 crystallization.
3.2.2. Interfacial tension
The low value of the interfacial tension at the boundary between oil and aqueous scale
inhibitor solution is one of the main properties of every chemical composition. Fig. 8 shows the
results of measuring the interfacial tension at the boundary between water solution (IW/FW, 50
% / 50 %) with scale inhibitor No. 1 and oil depending on the mass concentration of its organic
components. As shown in the figure, interfacial tension was decreased by increasing the
concentration of the organic components. Reduction in the interfacial tension was considerable
until mass percentage of organic components has reached 1.5 %. For further increase in the
concentration of the oil organic components, the interfacial tension has remained constant.
3.3. Results of CaCO3 inhibition effectiveness under static conditions
Efficacy of scaling inhibition on different reagents varies, but it is always directly
proportional to the inhibitor concentration until certain values. Thus, according to the curves of
scaling inhibition efficiency in Fig. 9, inhibitor No. 1 showed the maximum inhibition
effectiveness at 30 mg/L. As illustrated in Fig. 9, with increasing temperature, the efficiency was
slightly reduced. At high temperatures (about more than 80 ºC), the efficiency was reduced more
rapidly.
Scale inhibitor effectiveness is dependent upon the ionic content of the water. To
investigate the effect of ion concentration on inhibitor efficiency, synthetic waters with Ca2+

15
concentrations from 0.2 to 15 g/L were used at 80 ºC. Concentrations of the aqueous scale
inhibitor solutions were 15 and 30 mg/L. Fig. 10 illustrates the results of the inhibitor
effectiveness depending on Ca2+ concentration. As shown in the figure, inhibition effectiveness
was decreased by increasing Ca2+ concentration. At 30 mg/L of aqueous scale inhibitor solutions,
inhibitor No. 1 had an effectiveness of more than 90 % at any Ca2+ concentration. However, the
effectiveness of inhibitor No. 2 was less than 90 % when Ca2+ concentration is higher than 5 g/L.
3.4. CaCO3 scale formation and its inhibition in core sample
For quantitative assessment of formation damage, core flooding investigations were done
at reservoir temperature and pressure conditions. The tests were carried out at the injection rates
of 5, 10 and 20 mL/min of the solution (IW/FW, 50 % / 50 %) with and without scale inhibitors.
From the results of the inhibition efficiency under static conditions (section 3.2), inhibitors were
used at a concentration of 30 mg/L. Fig. 11 and Fig. 12 show the ratio of damaged permeability
(after CaCO3 precipitation) to initial permeability (Kd/Ki) in the three different cases: without
inhibitor, with the use of the inhibitors No. 1 and No. 2. In addition, each graph illustrates the
effect of flow rate on the permeability reduction due to CaCO3 precipitation in the core samples.
As shown in the figures, with increasing solution injection rate, Kd/Ki was decreased. Therefore,
higher flow rates lead to the lower CaCO3 precipitation. Consequently, damaged permeability
goes to the initial permeability value. As illustrated in the figures, inhibitors No. 1 and No. 2
reduced the formation damage due to CaCO3 precipitation in the core samples. Inhibitor No. 1
improved the permeability better than inhibitor No. 2.
4. Conclusions

16
Theoretical and experimental analysis of scale formation, allows us study the scale
prediction and parameters, which affect the inhibition under static and dynamic conditions. Thus,
the use of modern technology can optimize well operation with minimum precipitation and scale
formation. Various factors such as temperature, pressure, solution supersaturation in mixture of
injection and formation water, mass concentration of organic components in oil, rotational speed
in stirred vessel, inhibitor concentration and solution injection rate, affect the CaCO3 scale
formation. Based on the results of the experimental investigations, the following conclusion were
drawn:
1. The analysis of obtained results showed that an increase in reservoir temperature and a
decrease in reservoir pressure and the amount of injection water in the mixture with formation
water leads to increase the saturation index values for CaCO3 scale formation. CaCO3 was
formed when the solution was supersaturated with calcium and bicarbonate ions. The change in
the state diagram curves of CaCO3, which includes stable, metastable and unstable regions,
depended on the salt precipitation in the solution. The salt was precipitated at a concentration of
more than 24 mg/L.
2. The effect of rotational speed (at different Reynolds numbers) on the induction period of
CaCO3 formation during its nucleation from the supersaturated solution has been studied. With
an increase in Reynolds number up to 6487, the induction period of CaCO3 crystallization was
increased to 28 minutes. For higher values of the Reynolds number, no increase in the induction
period occurred.
3. Minimum amount of CaCO3 precipitation occurred in 1.5 % of organic components in oil
in the carbonate core samples. In addition, interfacial tension at the boundary of oil and aqueous
scale inhibitor solution was decreased with an increase in the amount of organic components in

17
oil. The interfacial tension was at the lowest value in 1.5 % of organic components. At values of
higher than 1.5 %, the interfacial tension was inconsiderable changed.
4. Scale inhibitors have been successfully prevented the CaCO3 formation. Effectiveness of
the developed scale inhibitor was not reduced considerably with increasing temperature and
concentration of calcium ions to high values. The results of the research allow confirming the
high efficiency of the developed inhibitor to prevent the CaCO3 scale formation under static
conditions.
5. Formation damage due to CaCO3 precipitation was decreased with an increase in the
solution injection rate. The developed scale inhibitor had the higher efficiency for preventing
CaCO3 scale precipitation under reservoir conditions for carbonate core samples. The results
provide a basis for the recommendations of the chemical reagent to prevent CaCO3 scale
precipitation in carbonate oil reservoirs.
List of symbols
A Cross sectional areas of core sample, cm2
C Salt concentration, mg/L
d Agitator diameter, m
D Diameter of core sample, cm
E Effectiveness of scale inhibitor, %
FW Formation water
IW Injection water
K Permeability of core sample, mD
Ksp Solubility product, mol2/L2

18
L Length of core sample, cm
MW Molecular weight of salt, g/L
N Rotational speed in stirred vessel, rev/s
q Injection rate of the solution, mL/min
Re Reynolds number
SI Saturation index
ST Scaling tendency

P Pressure drop, atm

Dynamic viscosity of solution, Pa.s
ρ Density of the solution, kg/m3

Porosity of core sample, %
[A] Anion concentration, mol/L
[Ca2+]0 Initial concentration of calcium ions in the solution before testing, mg/L
[Ca2+]1 Concentration of calcium ions in the solution after testing without scale inhibitor, mg/L
[Ca2+]2 Concentration of calcium ions in the solution after testing with scale inhibitor, mg/L
[M] Cation concentration, mol/L
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Fig. 1. An instrument for measuring the interfacial tension at the boundary between oil and water

24
Fig. 2. Schematic diagram of the experimental apparatus for core flooding; 1. Solution tanks; 2.
Pumps; 3. Piston accumulators; 4. Spiral sections of pipe (for temperature control); 5. Oven; 6.
Temperature sensor; 7. Core holder; 8. Rubber collar; 9. Pressure transducers at the inlet; 10.
Pressure transducers at the outlet; 11. Solution collection
a b
Fig. 3. Tendency of CaCO3 scale formation, depending on a) temperature, b) pressure
0
50
100
150
60 90 120 150
Scaling tendency-ST
Temperature (ºC)
at constant P=20 MPa
IW/SW, 30 % / 70 %
IW/SW, 50 % / 50 %
IW/SW, 70 % / 30 %
0
25
50
0.1 20.1 40.1 60.1
Scaling tendency-ST
Pressure (MPa)
at constant T=80 ºC
IW/SW, 30 % / 70 %
IW/SW, 50 % / 50 %
IW/SW, 70 % / 30 %

25
a b
Fig. 4. CaCO3 precipitation in absence of organic components, depending on a) temperature, b)
pressure
Fig. 5. Dependence of CaCO3 scale concentration on the temperature
0
200
400
600
800
40 70 100 130
CaCO3 precipitation (mg/L)
Temperature (ºC)
at constant P=20 MPa
IW/SW, 30 % / 70 %
IW/SW, 50 % / 50 %
IW/SW, 70 % / 30 %
100
250
400
550
0.1 20.1 40.1
CaCO3 precipitation (mg/L)
Pressure (MPa)
at constant T=80 ºC
IW/SW, 30 % / 70 %
IW/SW, 50 % / 50 %
IW/SW, 70 % / 30 %
0
10
20
30
60 80 100 120 140
CaCO3 concentration (mg/L)
Temperature (°C)
Second boundary of metastable state
First boundary of metastable state
Solubility curve
Stable
region
First metastable region
Second metastable
region
Unstable region

26
Fig. 6. Influence of the Reynolds number on the kinetics of CaCO3 crystallization at 80 ºC (for
solution of IW/FW, 50 % / 50 %)
Fig. 7. CaCO3 precipitation depending on the mass concentration of organic components in oil
(for solution of IW/FW, 50 % / 50 %)
600
1000
1400
1800
2200
015 30 45 60
Ca2+ concentration in brine
(mg/L)
Time (min)
Induction time
Re=8799
Re=6487
Re=3090
Re=913
0
40
80
120
040 80 120 160 200
CaCO3 precipitation per volume of core
(mg/cm3)
Time (min)
Without organics
0.5 % organics
1.5 % organics
2.5 % organics

27
Fig. 8. Interfacial tension at the boundary layer between aqueous solution of inhibitor No. 1 and
oil depending on concentration of organic components in the oil
0
5
10
15
0 0.5 1 1.5 2 2.5
Interfacial tension (mN/m)
Concentration of active organic components (%)
75
80
85
90
95
100
60 70 80 90 100 110 120
Inhibition efficiency ( %)
Temperature (ºC)
Inhibitor No. 1, 30 mg/L
Inhibitor No. 2, 30 mg/L
Inhibitor No. 1, 15 mg/L
Inhibitor No. 2, 15 mg/L

28
Fig. 9. Dependence of inhibitor effectiveness on temperature under static conditions (for solution
of IW/FW, 50 % / 50 %)
Fig. 10. Dependence of inhibitor effectiveness on initial concentration of calcium under static
conditions at 80 ºC
75
80
85
90
95
100
0.2 5.2 10.2 15.2
Inhibition efficiency (%)
Ca2+ concentration (g/L)
Inhibitor No. 1, 30 mg/L
Inhibitor No. 2, 30 mg/L
Inhibitor No. 1, 15 mg/L
Inhibitor No. 2, 15 mg/L

29
Fig. 11. Change in the permeability ratio depending on time without scale inhibitor at different
flow rates at 80 ºC (for solution of IW/FW, 50 % / 50 %)
a b
Fig. 12. Change in the permeability ratio depending on time with scale inhibitor a) No. 1, b) No.
2, at different flow rates at 80 ºC (for solution of IW/FW, 50 % / 50 %)
0.5
0.6
0.7
0.8
0.9
1
020 40 60 80 100
Permeability ratio-Kd/Ki
Injection time (min)
20 mL/min
10 mL/min
5 mL/min
0.5
0.6
0.7
0.8
0.9
1
025 50 75 100
Permeability ratio-Kd/Ki
Injection time (min)
Inhibitor No. 1 (30 mg/L)
20 mL/min
10 mL/min
5 mL/min
0.5
0.6
0.7
0.8
0.9
1
025 50 75 100
Permeability ratio-Kd/Ki
Injection time (min)
Inhibitor No. 2 (30 mg/L)
20 mL/min
10 mL/min
5 mL/min

30
Table 1. Characteristics of synthetic formation and injection waters
Water
pH
Ion content (mg/L)
Total
dissolved
salts (g/L)
Na+
K+
Ca2+
Mg2+
Cl-
SO42-
HCO3-
Formation water
(FW)
7.25
42367
1759
2043
574
71200
108
1615
119.666
Injection water
(IW)
7.55
11002
348
323
1425
20138
2479
74
35.789
Table 2. Used scale inhibitors
Inhibitor
number
Chemical composition
1 (new
inhibitor)
1-hydroxyethane 1, 1-diphosphonic acid (HEDP), C3H8O, NH4Cl,
HCl, polyethylene polyamine-N-methylphosphonic acid, water
2
Aminotrimethylenephosphonic acid (ATMP)
Table 3. Average properties of the core samples
Lithology
(%)
Porosity,
 (%)
Permeability,
K (mD)
Length,
L (cm)
Diameter,
D (cm)
limestone
clay
dolomite
81
7
12
17.3
26.1
3.55
2.93

31
Highlights
 Effect of organic components on the CaCO3 precipitation was investigated.
 The dependence of the induction period of CaCO3 crystallization on the flow rate was
determined.
 Performance of a new scale inhibitor for preventing CaCO3 formation was studied under
static and dynamic conditions.