Process for removing scale deposits in effluent dispatch lines
Field of the Invention
[0001] The present invention relates generally to the field of removal of scale deposits,
and in particular, to a sequential multi-step process for removing scale deposits
in dispatch lines carrying effluent water using a combination of chemicals.
Background of the Invention
[0002] Crude oil separation in oil fields produces effluent water as a by-product. The
effluent water consists of emulsified oil along with high concentration of salts
of alkali and alkaline earth metals depending on the in situ conditions.
Generally, effluent water is carried away for treatment from oil fields to
treatment plants via flowldispatch lines. The treatment of effluent water is
performed for reducing total suspended solids, turbidity, oil and grease,
bacterial activity, etc. Effluent water typically is known for high scaling
tendency and corrosivity which leads to impaimentifailure of facilities at oil
field installations. Further, due to high content of total dissolved solids in
effluent and exposure to low pressure conditions, flow lines are vulnerable for
scale deposition. Common scales formed are: Calcium carbonate (CaC03),
Calcium sulphate (CaSOd), Strontium sulphate (SrS04), Barium sulphate
(BaSOd), Iron carbonate (FeC03), Iron sulphide (FeS), Iron oxide (Fe304).
Besides flow lines, scaling also affects oil and gas wells, transportation pipes,
separators, etc. which may lead to production equipment failure, emergency
shutdown, increased maintenance cost, and overall decrease in production
operation.
[0003] Various methods have been devised for minimizing scale deposition in bore
wells, tubes, etc. at oil fields. Generally known processes include introducing
acidic fluids into the oil field installations for cleaning scale deposits. However,
the existing compositions of such acidic fluids do not produce desired results
mainly due to low reactivity with the scale deposits. As such, the existing
methods fail to provide an efficient scale cleaning process with excellent
results. Specifically, the current methods of cleaning scale deposits fail to
significantly improve the injection rate or effluent carrying capacity of the
dispatch lines.
[0004] In light of the above, there is a need for providing an efficient step-by-step
process for clearing of scale deposits at the oil field installations, and
specifically for flow lines. Further, there is a need for an improved chemical
composition which leads to clearing scale deposits in oil field installations.
addition all.^, there is a need for an effective process of cleaning scale deposits
which leads to significant change in injection rates or effluent carrying capacity
for the effluent flow lines.
Summary of the Invention
(00051 A process for treating scale deposits in dispatch lines is provided. In various
embodiments of the present invention, the process comprises injecting an
organic solvent into the dispatch lines, thereby, dissolving organic matter from
the scale deposits. Subsequently, the process comprises injecting a first
treatment fluid into the dispatch lines for dislodging the scale deposits. The first
treatment fluid comprises an acid, a wetting agent and a surfactant. After
injecting the first treatment fluid, a second treatment fluid is injected into the
dispatch lines for removing a substantial portion of the scale deposits. The
second treatment fluid comprises an acid, a wetting agent, a sequestering agent,
a surfactant and an acid corrosion inhibitor. Further to injection of the second
treatment fluid, a third treatment fluid is injected into the dispatch lines which
results in completion of reaction of the first treatment fluid and the second
treatment fluid with the scale deposits, thereby completely removing the scale
deposits. The third treatment fluid comprises an acid and a surfactant. Finally,
filtered effluent water through the dispatch lines is injected to remove traces of
treatment fluids injected into the dispatch lines. The process increases injection
rate of effluent water into the dispatch lines.
[0006] In an embodiment of the present invention, the organic solvent comprises an
organic aromatic hydrocarbon. In another embodiment of the present invention,
the volume of a treatment fluid to be injected is determined based on contact
time study of chemicals of the treatment fluid with the scale deposits. Further,
the injection during each of the steps of the process is performed at a
temperature range of 25-45OC.
[0007] In an embodiment of the present invention, the first treatment fluid comprises
2% acid by volume, 5% wetting agent by volume and 2% surfactant by volume.
The second treatment fluid comprises 7.5% acid by volume, 5% wetting agent
by volume, 3% sequestering agent by volume, 1% surfactant by volume, and
1% acid corrosion inhibitor by volume. The third treatment fluid comprises 2%
acid and 2% surfactant by volume.
[0008] In an embodiment of the present invention, the third treatment fluid further
comprises one or more of a wetting agent, a sequestering agent, and an acid
corrosion inhibitor. In an exemplary embodiment of the present invention, the
third treatment fluid comprises 15% acid, 3% sequestering agent, 2%
surfactant, 1% acid corrosion inhibitor by volume. In another exemplary
embodiment of the present invention, the third treatment fluid comprises 5%
acid, 5% wetting agent, 3% sequestering agent, 1% surfactant, and 1% acid
corrosion inhibitor by volume. In yet another embodiment of the present
invention, the third treatment fluid comprises 15% acid, 3% sequestering agent,
2% surfactant, 1% acid corrosion inhibitor by volume.
[0009] In an exemplary embodiment of the present invention, the total volume of fluids
injected during the process is determined based on inner diameter and length of
effluent dispatch lines. The volume of the injected organic solvent lies in the
range of 3% to 10% of the determined total volume. The volume of the first
treatment fluid lies in the range of 14% to 20% of the determined total volume.
The volume of the second treatment fluid lies in the range of 55% to 65% of the
determined total volume. The volume of the third treatment fluid lies in the
range of 20% to 30% of the determined total volume. The volume of the filtered
effluent water injected into the dispatch lines is equal to the determined total
volume.
Brief Description of Drawings
[0010] The present invention is described by way of embodiments illustrated in the
accompanying drawings wherein:
[OOll] Figures 1A and 1B illustrate a flowchart of a process for removing scale
deposits in effluent Bow lines, in accordance with various embodiments of the
present invention;
[0012] Figure 2 illustrates an 8" diameter flow line with scale deposits before
treatment using the multi-step process, in accordance with one embodiment of
the present invention;
[0013] Figure 3 illustrates a 4" diameter flow line with scale deposits before treatment
using the multi-step process, in accordance with one embodiment of the present
invention; and
[0014] Figure 4 illustrates a flow line (8" or 4" diameter) after treatment of scale
deposits in accordance with one embodiment of the present invention.
Detailed Description of the Invention:
[0015] A process for removing scale deposits in effluent dispatch lines in oil field
installations is provided. The scale deposits to be removed are studied to
determine characteristics of the deposits. Based on the characteristics, the
composition of fluids to be injected into the flow lines in oil field installations
is determined. The process includes a multi-step treatment of scale deposits
with a particular set of fluids for every step. Initially, an organic solvent is
injected in the effluent flow lines to dissolve organic matter in the scale
deposits. Further, a fluid comprising an acid, a wetting agent, and a surfactant
is injected into the effluent flow lines which facilitates wetting of scale deposits
surface and removal of emulsions. Subsequently, a fluid comprising an acid, a
wetting agent, a sequestering agent, a surfactant, and an acid corrosion inhibitor
is injected into the effluent flow lines. Furthermore, a fluid comprising an acid
and a surfactant is injected into the effluent flow lines which facilitates removal
of scales to a substantial extent. Finally, filtered effluent water is injected into
the effluent flow lines to remove any traces of fluids used during preceding
treatment steps. The fluids are used in optimized quantities during every step of
the multi-step process. The multi-step process of the present invention leads to
removal of scale deposits and significant improvement in the injection rates or
effluent carrying capacity of the effluent flow lines.
[0016] Throughout the specification, the term "treatment" along with its corresponding
semantic variants refers to an injection of a fluid in effluent dispatch lines in
order to minimize or removing the scale deposits in the dispatch lines. Further,
the terms "flow lines" and !'dispatch lines" along with their corresponding
semantic variants are interchangeably used throughout the specification.
[0017] The disclosure is provided in order to enable a person having ordinary skill in
the art to practice the invention. Exemplary embodiments herein are provided
only for illustrative purposes and various modifications will be readily apparent
to persons skilled in the art. The general principles defined herein may be
applied to other embodiments and applications without departing from the spirit
and scope of the invention. The terminology and phraseology used herein is for
the purpose of describing exemplary embodiments and should not be
considered limiting. Thus, the present invention is to be accorded the widest
scope encompassing numerous alternatives, modifications and equivalents
consistent with the principles and features disclosed herein. For purposes of
clarity, details relating to technical material that is known in the technical fields
related to the invention have been briefly described or omitted so as not to
unnecessarily obscure the present invention.
[0018] The present invention would now be discussed in context of embodiments as
illustrated in the accompanying drawings.
[0019] Figures 1A and 1B illustrate a flowchart of a process for removing scale
deposits in effluent flow lines, in accordance with various embodiments of the
present invention.
[0020] At step 102, one or more characteristics of scale deposits in effluent flow lines
of oil field installations are evaluated. In an embodiment of the present
invention, the scale deposits may comprise, but not limited to, one or more of
calcite, gypsum, quartz, albite, microline, pyrrhotite, hematite, ilmenite, and
sliderite. The scale deposits may also comprise one or more clay minerals
including, but not limited to, clinochlore, kaolinite, montmorillonite and illite.
In an embodiment of the present invention, one or more characteristics to be
evaluated for scale deposits comprise evaluating chemical composition,
solubility, contact time studies, and corrosion tendency of the scale deposits.
The evaluation is performed using methods known in the art. For example, a
inegascopic study of the scale deposits is performed to determine one or more
characteristics of the scale deposits. The evaluation of one or more
characteristics is further described in detail later with reference to Figures 2 and
3.
[0021] At step 104, composition of fluids to be injected into the effluent flow lines for
treatment of scale deposits is determined based on the evaluated characteristics
of the scale deposits. The composition of fluids to be injected may be optimized
based on the evaluated characteristics of the scale deposits. The composition of
fluids at every step is hrther described in detail later with reference to Figures
2 and 3. Additionally, the quantity of treatment fluids may as well be
determined. In an embodiment of the present invention, the volume/quantity of
fluid injection at one or more steps of the multi-step process is determined based
on length and diameter of cylindrically shaped effluent flow lines. For example,
the total volume to be injected at one or more steps may be determined based
on the formula:
Volume of treatment fluid at one or more stages = d l ;
wherein, r is the radius of the flow line, and 1 is the length of flow line from
which the scale deposits are to be removed.
The volurne of fluid(s) injected at each of steps 106, 108, 110 and 112 (as
discussed hereinafter) sums up to the total volume determined using the above
exemplary formula. In various embodiments of the present invention, the range
of volume injected at steps 106, 108, 11 0 and 112 lies in the following ranges
of the determined total volume. The injected volume of fluid@) at step 106
preferably lies in the range of 3% to 10% of the determined total volume. At
step 108, the injected volume of fluid(s) preferably lies in the range of 14% to
20% of the determined total volume. At step 11 0, the injected volume of fluid(s)
preferably lies in the range of 55% to 65% of the determined total volume. At
step 112, the injected volume of fluid(s) preferably lies in the range of 20% to
30% of the determined total volume. In an embodiment of the present invention,
the injected volume of fluid(s) at step 114 is equivalent to the determined total
volume.
100221 Further, the rate of injection of the treatment fluid is determined to ensure an
optimum contact time of the injected fluid with the scale deposits in the effluent
flow lines. In an exemplary embodiment of the present invention, the acid
concentration for injection at one of the steps of the multi-step process (as
discussed hereinafter) may be optimized based on solubility of the inorganic
portion of scale deposits. In another exemplary embodiment of the present
invention, the acid strength for injection may be optimized to reduce the level
of corrosion based on evaluated characteristics, in view of highly corrosive
nature of acids. The optimization of strengths of various fluids to be injected is
discussed in further detail later in the specification.
[0023] At step 106, an organic solvent is injected through the effluent dispatch lines.
1x1 an embodiment of the present invention, the organic solvent comprises an
aromatic hydrocarbon. The organic solvent injection facilitates dissolving
organic matter such as oil, grease, wax, etc. impregnated in the scale deposits
or sticking to effluent dispatch lines' surfaces. Additionally, the organic solvent
injection minimizes contact of acid (to be injected in next steps of the process)
with oily components of scale deposits, thereby facilitating the scale deposits
to react with treatment fluids which would be injected in the subsequent steps
of the process. The injection of organic solvent into one end of the effluent
dispatch lines at this step produces an output of organic solvent along with
dissolved oil deposits and sludge at the other end of the dispatch lines on
completion.
(00241 At step 108, a first treatment fluid is injected into the effluent flow lines. In an
embodiment of the present invention, the first treatment fluid comprises an acid,
a wetting agent and a surfactant. In an embodiment of the present invention,
the acid is hydrochloric acid, and the wetting agent is a mutual solvent (e.g.,
Ethylene Glycol Monobutyl Ether (EGMBE)). The quantity of said fluid is
determined based on length, and diameter of effluent flow lines, along with
contact time studies of the scale deposits. The contact time studies relate to
contact time of the injected treatment fluid with the scale deposits required for
dissolving/rernoval of scale deposits by the injected treatment fluid. Further, the
concentration of constituents of said fluid is optimized based on the evaluated
characteristics of the scale deposits. In an embodiment of the present invention,
the injected first treatment fluid comprises 2% acid, 5% wetting agent, and 2%
surfactant by volume. The said fluid performs one or more functions, such as
dislodging of scale deposits, leading to effective removal of scale deposits. The
acid in the fluid facilitates initiation of reaction between the added fluid and the
deposited scale. Further, the wetting agent in the fluid ensure that the insoluble
fines (e.g. clays) and metal surfaces remain wet, and further ensuringprevention
of any emulsion formation. Additionally, the wetting agent facilitates in
reducing absorption of surfactant and corrosion inhibitor to be injected during
the process. Moreover, the surfactant facilitates reduction of surface tension of
the fluids in the flow lines, as well as lowering of interfacial tension between
water and other immiscible liquids, thereby easing the flow of pumping
treatment fluids during the process. In an exemplary embodiment of the present
invention, the surfactant is preferably non-ionic in nature. The injection of the
first treatment fluid through the effluent dispatch lines produces an output of
largely soluble salts of metal chlorides, water and gas on completion of the
injection step.
[0025] At step 110, a second treatment fluid is injected into the effluent dispatch lines.
In an embodiment of the present invention, the second treatment fluid
comprises an acid, a wetting agent, a sequestering or chelating agent, a
surfactant and an acid corrosion inhibitor. The Injection of said fluid facilitates
removal of deposited scales to a substantial extent. The quantity of said fluid is
determined based on length, and diameter of effluent flow lines, along with
contact time studies of the scale deposits. Further, the concentration of
constituents of said fluid is optimized based on the evaluated characteristics of
the scale deposits. In an embodiment of the present invention, the injected
second treatment fluid at this step comprises 7.5% acid, 5% wetting agent, 3%
sequestering agent, 1% surfactant, and 1% acid corrosion inhibitor by volume.
The constituents of said fluid injected during the step performs similar functions
as discussed in the preceding step. Furthermore, the sequestering agent in the
fluid facilitates corrosion inhibition, and is naturally sequestered against iron
precipitation. Therefore, the sequestering agent acts on complex ions of iron
and other metallic salts to inhibit precipitation of iron. Additionally, the
sequestering agent minimizes any stress cracking of alloys. In an exemplary
embodiment of the present invention, the sequestenng agent is a slow reacting,
weakly ionizing acid. The injection of the second treatment fluid through the
effluent dispatch lines produces an output of largely soluble salts of metal
chlorides, water and gas on completion of the injection step.
[0026] At step 112, a third treatment fluid is injected into the effluent dispatch lines.
In an embodiment of the present invention, the composition of third treatment
fluid is similar to second treatment fluid. However, the concentration of the
fluid constituents is different from second treatment fluid. For example, the
third treatment fluid comprises 5% acid, 5% wetting agent, 3% sequestering
agent, 1% surfactant, and 1% acid corrosion inhibitor by volume. Further, the
second treatment fluid and the third treatment fluid may be performed at
different injection rates. Furthermore, different volumes of fluids may be
injected during steps 110 and 112. For example, step 110 inay be performed
with injection of 10 m3 of second treatment fluid, while step 112 may be
performed with injection of 5 m3 of third treatment fluid. In another
embodiment of the present invention, the third treatment fluid may not comprise
one or more of the wetting agent, the sequestering agent, and the acid corrosion
inhibitor. For example, the third treatment fluid comprises 2% acid and 2%
surfactant by volume. In another example, the third treatment fluid may
comprise 15% acid, 3% sequestering agent, 2% surfactant, 1% acid corrosioll
inhibitor by volume. The injection of the third treatment fluid through the
effluent dispatch lines ensures completion of reaction of treatment fluids with
the scale deposits, thereby leading to effective scale deposits removal from the
dispatch lines. The injection of the third treatment fluid through the effluent
dispatch lines produces an output of largely soluble salts of metal chlorides,
water and gas on completion of the injection step.
[0027] At step 114, filtered effluent water is injected into the effluent flow lines. The
filtered effluent water may be prepared by filtering effluent water through a
coarse filter. The coarse filter may be an 80-1 00 micron filter. In an embodiment
of the present invention, this step may additionally comprise a base being
injected along with filtered effluent water. In an exemplary embodiment of the
present invention, the base injected at this step comprises sodium bicarbonate
(2% v/v). The injection of filtered effluent water (with or without base) at this
step ensures removal of any traces of fluids used during the preceding treatment
steps of the multi-step process. Further, the injection of filtered effluent water
(with or without base) through the effluent dispatch lines produces an output of
soluble salts and water on completion of this injection step. In an embodiment
of the present invention, the step 114 may be performed after a substantial timegap
from the completion of step 112. For example, step 114 may be performed
four hours after completion of step 112. This time gap provides better results in
removal of any residual fluids and reaction products.
[0028] During any of the steps 106, 108, 110, 112, and 114, the injection of fluid is
performed in a temperature range of 25-45°C. Further, it may be apparent to a
person of skilled in the art that the above multi-step process of removing scale
deposits is not limited to dispatch lines, and is applicable to any other oil field
installation apparatus for treatment of scale deposits. The injection steps may
be performed using various pumpinglinjecting apparatus known in the art. For
instance, an exemplary apparatus for injecting the treatment fluids may be
performed using an acid pumper. Further, the multi-step process described
herein may be performed for flow lines which are above the ground and for
lines which are under the ground. It is to be noted that the above multi-step
process is exemplary, and usage of one or more constituents at a step may be
omitted. The above process of Figure 1 yields surprising results in removing
scale deposits in effluent dispatch lines. Consequently, it leads to significant
improvement in the injection rate (as will be discussed in the later sections of
specification).
100291 Further, as disclosed in FIG. 1, various fluids to be injected during the multistep
process for removing scale deposits in the effluent flow lines has been
disclosed by way of examples provided below.
[0030] Figure 2 illustrates an 8" outer diameter flow line with scale deposits before
treatment using the multi-step process, in accordance with one embodiment of
the present invention. Similarly, Figure 3 illustrates a 4" outer diameter flow
line with scale deposits before treatment using the multi-step process, in
accordance with an embodiment of the present invention. The exemplary flow
lines depict scale deposits at their inner peripheries. The exemplary flow lines
are made up of mild steel. A deposit sample of scale collected from each of the
two effluent flow lines (hereinafter referred to as "Sample 1" and "Sample 2")
was evaluated for determining one or more characteristics as per steps 102 and
104 (shown in Figure I), in accordance with an embodiment of the present
invention. The evaluated characteristics comprise of, but not limited to,
mineralogy and chemical composition. Further, effluent water, pumped through
each of the flow lines (hereinafter referred to as "Effluent 1" and "Effluent 2")
was evaluated for ionic composition. Additionally, a chemical solubility test
was carried out on scale deposit samples to determine percentage of organic
and inorganic components in the scale deposit samples.
[0031] Based on results of the evaluation processes, various observations can be drawn
with respect to one or more characteristics of the samples, as discussed
hereinafter.
Mineralogy of samples -
Sample 1 -The scale sample constitutes 62 % calcite, 9% Gypsum, 9% Quartz,
6 % Albite, and 4% Microcline. The clay mineral present in the scale sample is
6% of Clinochlore.
Sample 2 - The scale sample constitutes 55% calcite, 7% quartz, 7% pyrrhotite,
5% hematite, 5% Ilmenite, 5% microcline, and 2% siderite. The clay mineral
present in the scale sample is 11% of Kaolinite, 2% montmorillonite and 1% of
Illite.
Chemical composition of deposits:
Sample 1 - The ionic composition of the acid soluble part of sample indicates
higher concentration of calciumti (1588 mg/l) followed by Magnesiumc ions
(768 mg/l). Further, the solubility of the sample 1 as received in an organic
solvent is determined to be 10.02%.
Sample 2 -The ionic composition of the acid soluble part of the solid sample
shows high content of calcium* (634 mgil) followed by iron content (538 mgll)
and magnesiumtt ions (54 mg/l). Further, the solubility of sample 2 is around
1.6% in an organic solvent.
Phvsico-chemical analysis of effluent water
Effluent 1 - A physico-chemical analysis of effluent water indicated that the
effluent water has a pH of 8.17, salinity of 6757 mg/l and TDS of 9682 mg/l.
Further, the calcium and magnesium content in the effluent water are
determined as 20 mg/l and 15 mg/l respectively. Furthermore, the bicarbonate
content is 2135 mg/l, which contributes to carbonate type of scales.
Effluent 2 - A physico-chemical analysis of effluent water indicated that the
effluent water has a pH of 8.17, salinity of 5031 mg/l and TDS of 9813 mg/l.
Further, the calcium and magnesium content in the effluent water are
determined as 68 and 7 mg/l respectively. Furthermore, the bicarbonate content
is 3477 mdl, which contributes to carbonate type of scales.
Scale forming tendency
Effluent 1 - Analysis of effluent water shows 38% fall in hardness at 60°C
indicating precipitation in the installation. Scaling index calculated
theoretically based on, for example, Stiff and Davis scaling index, showed
values ranging from 0.89, 1.41 and 2.01 at 40, 60 and 80°C respectively. It
would be apparent to a person skilled in the art that the values clearly confirm
tendency of scale formation in the flow lines.
Effluent 2 - Bench scale studies canied out for effluent water indicated
percentage fall in hardness to nil, 28% and 54% at 40 OC, 60 OC and 80°C
respectively. Scaling index calculated theoretically based on, for example, Stiff
and Davis scaling index, ranged &om 1.6 to 2.9. It would be apparent to a person
skilled in the art that the values show moderate to-severe scale forming tendency
in the specified temperature ranges.
[0032] Based on the above evaluation of scale deposits and effluent water from the
flow lines, an exemplary multi-step process of the present invention is applied
each of the flow lines. An exemplary process for 1OOm length of the 8" diameter
flow line which is detailed below:
Example 1 -
a) Step 106 (shown in Figure 1) - Injecting 100 litres of organic solvent;
b) Step 108 (shown in Figure 1) - Injecting 900 litres of formulation
consisting of 2% acid + 5% wetting agent + 2% surfactant;
c) Step 110 (shown in Figure 1) - Injecting 3 m3 of acid fluid consisting of
7.5% acid + 5% wetting agent + 3% sequestering agent + 1% surfactant
+ 1% acid corrosion inhibitor;
d) Step 112 (shown in Figure 1) - Injecting 1 m3 of acid formulation
consisting of 2% acid + 2% surfactant.
e) Shutting the line for four hours; and
f) Step 114 (shown in Figure 1) - Injecting 5 m3 of filtered effluent water.
(00331 In another exemplary embodiment of the present invention, an exemplary
multi-step process of the present invention is applied to 3km length of a 4"
diameter underground flow line which is detailed below.
Example 2 -
a) Step 106 (shown in Figure 1) - Injecting 500 litres of organic solvent;
b) Step 108 (shown in Figure 1) - Injecting 2.5 m3 of fluid consisting of 2%
Acid + 5% wetting agent + 2% surfactant;
c) Step 110 (shown in Figure 1) -Injecting 10 m3 of fluid consisting of 7.5%
Acid + 5% wetting agent + 3% sequestering agent + 1% surfactant + 1%
acid corrosio~iln hibitor;
d) Step 112 (shown in Figure 1) - Injecting 5 m3 of fluid consisting of 5%
acid + 5% wetting agent + 3% sequestering agent + 1% surfactant + 1%
acid corrosion inhibitor at an injection rate of 6 m3/hour; and
e) Step 114 (shown in Figure 1) -Injecting 18 m3 of filtered effluent water
at an injection rate of 12 m3/hour.
[0034] An exemplary multi-step process of the present invention as applied to 350
meters length of a 4" diameter effluent flow line is detailed below.
Example 3 -
a) Step 106 (shown in Figure 1) - Injecting 20 litres of an organic solvent +
5 litres of wetting agent + 4 litres of surfactant;
b) Step 108 (shown in Figure 1) - Injecting 500 litres of acid fluid consisting
of 2% acid + 5% wetting agent + 2% surfactant;
c) Step 110 (shown in Figure 1) -Injecting 1.5 m3 of acid fluid consisting of
7.5% acid + 5% wetting agent + 1% Surfactant + 1% acid corrosion
inhibitor at the rate of 0.5 m3/hour;
d) Step 112 (shown in Figure 1) - Injecting 0.5 m3 acid fluid consisting of
15% acid + 3% sequestering agent + 2% surfactant + 1% acid corrosion
inhibitor at an injection rate of 0.5 m3/hour; and
e) Step 114 (shown in Figure 1) - Injecting 2 m3 of filtered effluent water.
[0035] In addition to the above discussed evaluation processes, further evaluations
were performed for determining an optimum quantity of fluid constituents for
the multi-step process, according to an embodiment of the present invention. A
few exemplary evaluations and optimization of fluid constituents are detailed
below:
Optimization of acid system
Sample 1 - The effect of acid concentration in a range of 1-15% on solubility
of the inorganic portion of the deposit sample in presence of 3% sequestering
agent, and 5% or 10% wetting agent was studied. As the concentration of acid
was increased, an increase in solubility was consistently observed. In a fluid
comprising 5% acid strength with 3% sequestering agent and 5% wetting agent,
the deposit sample showed solubility of around 85%. Further, with 7.5% and
15% acid, deposit sample showed around 100% solubility, thereby leaving a
small amount of residue.
Sample 2 -Due to corrosive nature of acids, the acid strength was optimised in
order to reduce the level of corrosion. The effect of acid concentration in arange
of 3-15% on solubility of the inorganic portion of the sample in presence of 3%
sequestering agent and 5% wetting agent was studied. The fluid with 3%
sequestering agent and 5% wetting agent, and 5, 7.5, and 15% acid, deposit
sample showed solubility of about 81,85 & 90% respectively.
Contact time studies
Sample 1 - Contact time of different acid systems containing 5% wetting agent
and 3% sequestering agent was studied on the sample. The duration of almost
complete dissolution of sample was observed to be 5.5 hours in 5 % acid,
whereas in 7.5% acid, it took about 3.5 hours.
Sample 2 - Contact time study of the sample for a duration of 1 to 6 hours in
optimised acid system containing 7.5% acid, 3% sequestering agent and 5%
wetting agent was studied on the solid sample. Although solubility of scale
sample showed an incremental increase with time. Around 75% and 81% of
scale sample was dissolved in 2 and 4 hours respectively. This can be attributed
to the presence of oxide (Hematite) and sulphides (Pyrrhotite) of Iron in deposit
sample that reduce the rate of solubility. Hence, it was concluded that a contact
time of 4 hours is most effective for cleaning the flow line.
Corrosion inhibitor dose optimisation
Samples 1 and 2 - Chemical treatment by adding an acid corrosion inhibitor
(ACI) minimizes the effect of corrosion during cleaning operation of the flow
line. The quantity of ACI is optimised taking 0.5% and 1% of ACI along with
a suggested acid formulation.
The experimental results revealed that 1% of ACI is effective to inhibit
corrosion both in 2 and 4 hours of exposure time in the system with 5 and 7.5%
acid and additives.
[0036] On completion of the above exemplary processes for 8" and 4" diameter flow
lines, the scale deposits are substantially cleared, as depicted in Figure 3 of the
present invention. Experimental results data showed a substantial change in the
effluent injection rate through the flow lines after completion of the multi-step
processes. For example, the effluent injection rate in the flow lines of above
discussed examples 1 and 3 was observed to be 18m3/hr due to scale deposits
over the years from an initial value of 50m3ihr. After applying the multi-step
process as discussed in conjunction with examples 1 and 3, the effluent injection
rate through the fl ow lines improved to 40m3ihr.
[0037] It may be apparent to a person of ordinary skill in the art that these observations
are merely exemplary, and several other inferences and observations can be
drawn from the samples and the effluents.
We claim:
1. A process for treating scale deposits in dispatch lines comprising the steps of:
injecting an organic solvent into the dispatch lines, thereby dissolving organic
matter from the scale deposits;
injecting a first treatment fluid comprising an acid, a wetting agent and a
surfactant into the dispatch lines, thereby dislodging the scale deposits;
injecting a second treatment fluid comprising an acid, a wetting agent, a
sequestering agent, a surfactant and an acid corrosion inhibitor into the dispatch
lines, thereby removing a substantial portion of the scale deposits;
injecting a third treatment fluid comprising an acid and a surfactant through the
dispatch lines, the injection of the third treatment fluid resulting in completion
of reaction of the first treatment fluid and the second treatment fluid with the
scale deposits, thereby completely removing the scale deposits; and
injecting filtered effluent water through the dispatch lines to remove traces of
treatment fluids injected into the dispatch lines, thereby increasing injection rate
of effluent water into the dispatch lines.
2. The process as claimed in claim 1, wherein the organic solvent comprises an
organic aromatic hydrocarbon.
3. The process as claimed in claim 1, wherein volume of a treatment fluid to be
injected is determined based on contact time study of chemicals of the treatment
fluid with the scale deposits.
4. The process as claimed in claim I, wherein the injection during each of the steps
of the process is performed at a temperature range of 25-45°C.
5. The process as claimed in claim 1, wherein the first treatment fluid comprises
2% acid by volume, 5% wetting agent by volume and 2% surfactant by volume.
6. The process as claimed in claim 1, wherein the second treatment fluid comprises
7.5% acid by volume, 5% wetting agent by volume, 3% sequestering agent by
volume, 1 % surfactant by volume, and 1% acid corrosion inhibitor by volume.
7. The process as claimed in claim 1, wherein the third treatment fluid comprises
2% acid and 2% surfactant by volume.
8. The process as claimed in claim 1, wherein the third treatment fluid further
comprises one or more of a wetting agent, a sequestering agent, and an acid
corrosion inhibitor.
9. The process as claimed in claim 8, wherein the third treatment fluid comprises
15% acid, 3% sequestering agent, 2% surfactant, 1% acid corrosion inhibitor
by volume.
10. The process as claimed in claim 8, wherein the third treatment fluid comprises
5% acid, 5% wetting agent, 3% sequestering agent, 1% surfactant, and 1% acid
corrosion inhibitor by volume.
11. The process as claimed in claim 8, wherein the third treatment fluid comprises
15% acid, 3% sequestering agent, 2% surfactant, 1% acid corrosion inhibitor
by volume.
12. The process as claimed in claim 1, wherein total volume of fluids injected
during the process is determined based on inner diameter and length of effluent
dispatch lines.
13. The process as claimed in claim 12, wherein volume of the injected organic
solvent lies in the range of 3% to 10% of the determined total volume.
14. The process as claimed in claim 12, wherein volume of the first treatment fluid
lies in the range of 14% to 20% of the determined total volume.
15. The process as claimed in claim 12, wherein volume of the second treatment
fluid lies in the range of 55% to 65% of the determined total volume.
16. The process as claimed in claim 12, wherein volume of the third treatment fluid
lies in the range of 20% to 30% of the determined total volume.
17. The process as claimed in claim 12, wherein volume of the filtered effluent
water injected into. the dispatch lines is equal to the determined total volume.