This paper is a literature review on methods to control scale formation using various chemicals; and its economic feasibility in the petroleum industry.

1. Scale Formation problems in Oil & Gas Industry : Its reduction
procedures by Chemical Introduction
Oilfield scaling is serious for oil and gas industry. Every year problem with scale, costs industry millions
of dollars in damage and the lost production. The scale is one of the leading cause of worldwide decline.
In the North Sea area, 28% decline is related to the formation of scale.
The scale is an assemblage of deposits that clog perforations , casings, production tubings, valves ,
pumps and down holes, completion equipment, thereby clogging the well-bore and preventing fluid-
flow. Most scales found in oil fields forms either by direct precipitation from water that occurs naturally
in reservoir rocks or as a result of produced water becoming over-saturated with scale component when
two incompatible glasses of water meet downhole. Whenever an oil or gas well produces water or water
injection is used to enhance recovery, there is the possibility that scale will form.
The global cost of scale is estimated in more than USD 4 billion a year. Scale control form can for some
fields’ be the single biggest operational cost. The economic consequence of scale has estimated to have
the highest impact on North America and South America. In the coming years, scale costs will increase
as more as reservoir become mature and require pressure maintenance by water flooding to increase
recovery. The formation of scale may occur in the reservoir, in the wellbore or in the surface facilities.
Scale deposits may cause Formation damage by blocking pore throats, Flow restriction by blocking flow
lines and tubing, Completion damage by plugging perforations, screens, advanced completions, and
gravel packs, Choke and safety valve failure, Pump wear, Flow meter and instrumental failure,
Corrosion underneath scale deposits etc. Suspended solids can cause Plugged formation, Reduce
oil/water separator efficiency and Settlement in topside equipment.
This paper is a literature review on methods to control scale formation using various chemicals; and its
economic feasibility in the petroleum industry.

2. ANNEXURE 1 Scale Formation
ANNEXURE 2 Problems caused by scales
ANNEXURE 3 Potential scale formation site
ANNEXURE 4 Experiment Conducted
CONCLUSION
OUTLINE

3. ANNEXURE 1 : SCALE FORMATION
PRINCIPLE
In a hydrocarbon reservoir, before a well is drilled and completed, the fluids in the formation is saturated
with dissolved salt. After the well is drilled the fluids are no longer remain in equilibrium and salts may
start to precipitate. This means that scale begins to form when such the solubility limit for one or more
than one components is exceeded .
Formation of scale depends on parameters, such as
 change in pressure and temperature
 degree of agitation/turbulence during formation of crystals
 size and number of seed crystals
 degree of super-saturation
 change in pH of solution.
Where, and represent the salts where M being the cation with a positive charge and X is the
anion with a negative charge
Ksp is called the solubility product( equilibrium constant for the dissolution of the salt). The solubility
product is a measure of how many moles of ions per unit volume of solvent there can be in a system
before a salt precipitates out . If the saturation ratio equals 1.0 the solution is saturated and neither
precipitation nor dissolution of the salts will occur.
 When the SR is less than 1.0 the solution is under-saturated and precipitation will not occur.
 When the SR is greater than 1.0 the solution is oversaturated and precipitation of the salts may
occur ( SCALE FORMATION )
This will, however, depend on the kinetics of the precipitation reaction. Some salt do not start
spontaneous precipitation even if they are many hundred times super-saturated .
Produced water that goes through a pH shift, a temperature or pressure change or are in contact with
incompatible water, do not always produce scale, even though the produced water has become
oversaturated. This is because scale must grow from solution to form. The process is called nucleation
Saturation Ratio for salts = [ ][ ]/ Ksp

4. and is the first stage in forming scale. Nucleation is the creation of a sub particle or ion cluster consisting
of several individual scaling ions. There are two different nucleation processes called homogeneous
nucleation and heterogeneous nucleation. Homogeneous nucleation is a process where scale growth
starts in a supersaturated solution with ion pairs forming single crystals in solution Heterogeneous
nucleation is a process where scale crystals start to grow on substrates like metallic surfaces, sand grains
or on pre-existing surface defects.
PROCESSES OF SCALE FORMATION
 Incompatible mixing
Scale from incompatible mixing occurs when two incompatible waters like injected seawater and
formation water gets mixed downhole. The produced water then gets oversaturated with scale
components. This happens because seawater has a high content or sulfate (SO4
-2
) and formation
water is rich in ions such as calcium (Ca+2
) and barium (Ba+2
). Mixing of these two waters leads
to precipitation of sulfate scales, such as BaSO4.
 Evaporation
When a mixture of hydrocarbon gas and formation water is produced simultaneous, evaporation-
induced scale may occur. A pressure drop caused by reduced hydrostatic pressure leads to an
expansion of the hydrocarbon gas and the hot brine phase evaporates. The salt concentration will

5. then increase above the solubility limit and salt will precipitate. Halite (NaCl) scale in High
temperature High pressure (HTHP) wells is the most common scale type to be formed this way.
 Auto-Scaling
This occurs when the natural water in the reservoir undergoes a change in pressure and/or
temperature when it is produced. Normally an increase in temperature tends to increase water
solubility of a salt which implies more ions gets dissolved at high temperatures. Similarly,
decrease in pressure tends to decrease the water solubility.

6. ANNEXURE 2 : PROBLEMS CAUSED BY SCALES
The formation of scale may occur in the reservoir, in the wellbore or in the surface facilities. Scale
deposits may cause
 Formation damage by blocking pore throats.
 Flow restriction by blocking flow lines and tubing.
 Completion damage by plugging perforations, screens, advanced completions, and gravel packs.
 Choke and safety valve failure
 Pump wear
 Flow meter and instrumental failure
 Corrosion underneath scale deposits.
Suspended solids can cause
 Plugged formation
 Reduce oil/water separator efficiency
 Settlement in topside equipment

7. ANNEXURE 3 : POTENTIAL SCALE FORMATION SITES
Case 1 : At the surface water injection facility where incompatible sources of water are mixed prior to
injection
Case 2 : In injection wells where the injected water starts to mix with the reservoir formation water.
Case 3 : Downhole in the reservoir where the injected water displaces formation water
Case 4 : Downhole in the reservoir where the mixed injected water and formation water are about to
reach the range of producing wells
Case 5 : Production tubing
Case 6 : At the connection of a branched zone where each branch produces different waters
Case 7 : At the manifold of producing zone where water is produced from different blocks within the
same producing zone.
Case 8 : At topside facility where produced fluids are mixed with different zones to separate oil and gas
from produced waters, or in pipelines that transport produced fluids to on-shore processing facilities.

8. ANNEXURE 4 : EXPERIMENTS CONDUCTED
• Collection of samples of casing and tubing was done by PDPU Alumni from ONGC Ahmedabad
(samples of KG Basin)
• Analysis of samples of casing and tubing for the identification of minerals was done in PDPU Solar
Department via X-Ray Diffractometer ( measuring instrument for analyzing the structure of a material from the scattering pattern
produced when a beam of radiation or particles (such as X-rays or neutrons) interacts with it )
• The analysis of the peaks obtained was done using the HIGHSCORE PLUS ( comprehensive phase
identification software used in XRD with additional functionalities of profile fitting, crystallographic and extended cluster analysis )
• The casing and tubing samples were tested in the chemical laboratory for the removal of scales by
increasing concentration of acids
• The variation of the removal of scales with concentration of acids was also noticed and the de-scaling
rate was calculated.
• After the completion of chemical experiment the samples underwent through XRD again and no or
fewer peaks were obtained which assured the removal of scales.
 Scale inhibition is a chemical treatment used to control or prevent scale from forming in a
producing well. Scale inhibitors are water-soluble chemicals that are designed to prevent or
retard the nucleation and the crystal growth of inorganic scales. They can reduce the rate of scale
formation to almost zero. For a scale inhibitor to be considered as a good inhibitor it must be
Stable : It must be sufficiently stable tinder the conditions imposed.
Compatible : It must not interfere with the action of other oilfield chemicals, nor be affected . It must be
compatible with the chemical injection system under operating them.
Efficient : It must be able to inhibit the scale in question, irrespective of the mechanisms operating.

9. N
Y
N
Y
Y
Scale samples from Casing and Tubing
X-Ray Diffraction
Graph : Intensity vs. 2 θ/degree
Peaks obtained
Identification of scale type
Removal Techniques by use of HCl, HNO3,
HCOOH, H2SO4 , Oxalic acid and sulphamic
acid
Analysis of New Peaks
If
Changes in peak visible
Experiment successful
Feasibility and Viability Parameters with effective
cost reduction, optimizing removal of scales
Scales not removed by chemical
Introduction ; Alternate methods
recommended
Absence of potential scales

10. CASE 1 : CASING
1. Effect of concentration of HNO3 on weight loss of the sample
Concentration Time
(minutes)
Initial
weight
sample
( g )
Final
weight
sample
( g )
Dissolved
scale ( g )
%-
dissolution
Rate of
de-scaling
1% 60 5 4 1 20 0.3333
2% 60 5 3.6 1.4 28 0.466
3% 60 5 2.2 2.9 58 0.9666
4% 60 5 1.7 3.2 64 1.066
5% 60 5 0.9 4.1 82 1.366
2. Effect of concentration of HCl on weight loss of the sample
Concentration Time
(minutes)
Initial
weight
sample
( g )
Final
weight
sample
( g )
Dissolved
scale ( g )
%-
dissolution
Rate of
de-scaling
1% 60 5 3 2 40 0.666
2% 60 5 2.5 2.5 50 0.833
3% 60 5 1.4 3.4 68 1.133
4% 60 5 1 4 80 1.333
5% 60 5 0.3 4.7 94 1.566
3. Effect of concentration of H2SO4 on weight loss of the sample
Concentration Time
(minutes)
Initial
weight
sample
( g )
Final
weight
sample
( g )
Dissolved
scale ( g )
%-
dissolution
Rate of
de-
scaling
1% 60 5 5 0 0 0
2% 60 5 5 0 0 0
3% 60 5 4.4 0.6 12 1.932
4% 60 5 4.5 0.5 10 0.166
5% 60 5 4.5 0.5 10 0.166
4. Effect of concentration of HCOOH on weight loss of the sample
Concentration Time
(minutes)
Initial
weight
sample (
g )
Final
weight
sample (
g )
Dissolved
scale ( g )
%-
dissolution
Rate of
de-scaling
1% 60 5 4 1 20 0.333
2% 60 5 4 1 20 0.333
3% 60 5 3.5 1.5 30 0.5
4% 60 5 3 2 40 0.666

11. 5% 60 5 2.7 1.3 26 0.433
5. Dissolved mass of scale in casing in different acid solution for 5g sample in 60 mins.
Concentration Time
(minutes)
% - dissolution
HNO3 HCl H2SO4 HCOOH
1% 60 1 2 0 1
2% 60 1.4 2.5 0 1
3% 60 2.9 3.4 0.5 1.5
4% 60 3.2 4 0.5 2
5% 60 4.1 4.7 0.5 2.3
0
20
40
60
80
100
1 2 3 4 5
Dissolvedscale(%)
Chemical Treatment on casing scale sample
HCOOH
H2SO4
HCl
HNO3
Formulas
Average specific rate of de-scaling ( R ) = ( mloss / msample ) x t

12. CASE 2 : TUBINGS
1. Dissolved mass of scale in casing in different acid solution for 5g sample in 60 mins
Concentration Time
(minutes)
% - dissolution
HNO3 HCl H2SO4 HCOOH
1% 60 0.5 1.5 0 0
2% 60 0.92 2 0 0.24
3% 60 1.4 2.9 0.2 0.76
4% 60 1.98 3.5 0.34 1.12
5% 60 2.77 4.2 0.51 1.76
0
10
20
30
40
50
60
70
80
90
1 2 3 4 5
DissolvedScale(%)
Chemical Treatment on tubing scale samples
HCOOH
H2SO4
HCl
HNO3

13. CASE 3 : On an average scale dissolution ( % ) vs Concentration of various acids can be inferred as

14. CONCLUSIONS
In order to prevent scale economically, inorganic acids ( except H2SO4 ) proved to be more effective as
compared to organic acids. HCl and HNO3 are better candidates to be used for chemical de-scaling of
tubing and casing. HCl may provide 30-50% saving on circulation time as compared to HNO3 based on
rate of dissolution. XRD plots also shown great variation after chemical treatment signifying scale
removal.
Fig. represents XRD plots before and after acid treatment in CASINGS
Fig. represents XRD plots before and after acid treatment in TUBINGS

15. REFERENCE
1. Femier WW and M. Ziauddin, removal and inhibition of organic scale in oilfield environment
2008.
2. Kelund M.A Productions chemical for oil and gas Industry 2009
3. Norwegian Petroleum Directorate
4. Al. Salami, AR and AA Momen, Downhole and Topside scale challenge “ Removal, prevention
and inhibition technology for scales “ , 2000
5. Crabtree, fighting scale- Removal and Prevention in Oilfield review , 1999
6. petrowiki.org/Scale_problems_in_production
7. www.kemira.com/en/industries-applications/Pages/scale-inhibition-production.aspx
8. Prediction of Scale Formation Problems in Oil Reservoirs and Production Equipment due
to Injection of Incompatible Waters Authors J. Moghadasi, A. Sharif, H. Müuller-Steinhagen,
M. Jamialahmad