Investigation of Acid-Induced Emulsion
Formation and Asphaltene Precipitation
in Low Permeability Carbonate
Reservoirs
Authors: Tariq A. Al-Mubarak, Dr. Mohammed H. Al-Khaldi, Hussain A. Al-Ibrahim, Majid M. Rafie and
Omar Al-Dajani
ABSTRACT
The increasing demand for energy has extended the development horizon toward relatively tighter formations all over the
world. In Saudi Arabia, hydrochloric (HCl) and organic acids
have been used extensively to enhance well productivity or
injectivity in low permeability formations. The use of these
acids, however, is associated with severe formation damage,
which is attributed to acid-oil emulsion formation and/or asphaltene precipitation in some of the low permeability carbonate reservoirs. Consequently, a detailed study of different
factors that influence the mechanisms of acid-oil emulsion formation and asphaltene precipitation was carried out for these
reservoirs. Several compatibility studies were conducted using
representative crude samples and different acid systems, such
as HCl and formic acid. The experiments were conducted at
various temperatures up to 240 °F using high-pressure/high
temperature (HPHT) aging cells for both live and spent acid
samples; some of the experiments also included anti-sludge,
iron control and demulsifier chemical additives. In addition,
another set of experiments was performed in the presence of
ferric ions (Fe3+). The total iron concentration in these experiments varied between 0 ppm and 1,000 ppm.
The results obtained from this study revealed that the acid
systems were not compatible with several representative oil
field samples. The amount of asphaltene precipitation and the
stability of the emulsions created increased significantly in the
presence of Fe3+. Several wells that had already been acidized
therefore showed major damage.
This article discusses different tests conducted to identify,
quantify and treat acid-oil emulsion formation and/or asphaltene precipitation in tight carbonate reservoirs. It also provides
details of a special solvent treatment fluid recommended to revive dead wells that were damaged by acid-induced emulsion
formation and asphaltene precipitation.
INTRODUCTION
The Lower Fadhili (LF) formation is the deepest of the Upper
Jurassic limestone reservoirs in field F. Underlying two other
carbonate reservoirs, the LF formation has been appraised as a
relatively lower quality formation, with a reservoir quality inFALL 2015
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
dex of ~0.13, a flow zone indicator of ~0.73 and a net to gross
ratio of ~0.62. This reservoir is heterogeneous with clay-rich
limestone/dolomite, having permeability in the range of 1 millidarcy (md) to 15 md and porosity ranging between 5% and
20%. Production in the LF formation is expected to be more
challenging than in common reservoirs due to its low kh, a
high hydrogen sulfide (H2S) content of ~7% and its crude oil
quality.
The wells in this reservoir are drilled as horizontal multilateral wells and completed as open hole completions. Several
wells have been acidized using treatments based on adjacent
field recipes, but acidizing in these cases resulted in complete
loss of production. To discover the cause, the LF oil was tested
and found to have a tendency to precipitate asphaltene. The
calculated colloidal instability index (CII) for the LF oil was
found to be above 0.9, indicating that the LF oil is unstable,
and as noted, tends to precipitate asphaltenes1. The LF formation was drilled with oil-based mud (OBM), which created an
OBM cake that acted as an impermeable barrier on the formation face; the subsequent mud cake removal required acid
treatment. While hydrochloric (HCl) and organic acids have
been extensively used in acid stimulation treatments and acid
washes to enhance well productivity or injectivity, one main
potential problem associated with these acids is incompatibility issues with the reservoir's oil — which appeared to be a
factor with these wells. Acid-oil incompatibility causes precipitation of asphaltene particles, forming a thick sludge that can
plug the formation, resulting in severe formation damage2-4.
Emulsion Formation and Asphaltene Precipitation
Asphaltenes are negatively charged particles, composed mainly
of condensed aromatic ring structures containing oxygen, sulfur and nitrogen atoms. Asphaltenes exist in heavy crude oil as
dispersed colloidal particles that are stabilized by adsorbed
resin “maltene” particles. Both asphaltenes and resins form
stabilized micelles in heavy crude oil2. When these stabilized
micelles are disrupted by acid contact, the result is asphaltene
precipitation, triggered by two main mechanisms: dissolution
of resins and neutralization of asphaltenes. Following the dissolution of resins and neutralization of asphaltenes by proton
ions, H+, the destabilized colloidal asphaltene particles form
large aggregates, which precipitate out of heavy crude oils and
form deposits at the formation pore throats. The precipitation
therefore plugs the formation and causes severe damage5. The
degree of acid-induced sludge accumulation is affected by several factors. Two main factors that can increase the degree of
asphaltene precipitation are the type/strength of the acid used
and the presence of contaminants, such as iron. Generally, asphaltene precipitation is relatively higher when heavy oil contacts high strength HCl acid; compared to live HCl acid,
organic and spent HCl acids have less potential for causing
sludge in asphaltic crudes. The presence of ferric ions (Fe3+),
though, can aggravate the asphaltene precipitation. It results in
flocculation of asphaltene particles following their coordination with different functional groups present in heavy oil, such
as phenolic hydroxyl3, 4. Acid-oil sludge can be reduced or prevented by minimizing the acid’s contact with the oil. One way
to achieve this is by using a preflush ahead of the main acid
stage, which acts as a barrier between the reservoir’s heavy oil
and the injected acid. This preflush fluid contains mainly mutual solvents, such as ethylene glycol monobutyl ether. Another
cost-effective method is to add surfactants to the injected acid.
The surfactant additive acts as an anti-sludging agent to prevent asphaltene precipitation5.
Another potential problem associated with acid-oil interactions is the formation of emulsions. Generally, the formation
of emulsions in oil is due to the presence of polar compounds,
“resins,” and heterocyclic compounds, such as acids, bases,
phenolics, asphaltenes and high molecular weight complex
compounds, which act like a surfactant. They trap droplets of
water — 1 µm to 20 µm — in the oil phase. Volatile aromatic
compounds, mono-aromatics and polycyclic aromatics in
crude oils, such as benzene and ethylbenzene, dissolve asphaltenes and resins. Therefore, crude oils containing higher
quantities of these volatile compounds have a lower tendency
to form emulsions when they come in contact with water6, 7.
Drill-in Fluids and Mud Cake Removal
Drill-in fluids (DIFs) are commonly used in drilling the pay
zone of many horizontal/multilateral wells. DIF systems are
typically designed by incorporating xanthan gum, starch or
polyanionic cellulose with bridging agents, such as calcium
carbonate (CaCO3). Compared to regular mud systems, DIF
systems are relatively clean and cause less formation damage
to the target zone. They are designed to form a thin, impermeable mud cake on the borehole wall in permeable formations
via filtration into the rock pores. The formed mud cake seals
the wellbore and prevents both the fluid filtrate and the
drilling solids from invading and damaging the pay zone while
the well is drilled.
Once drilling activities are completed, effective mud cake removal is essential to restore the well productivity or injectivity
and to reduce DIF associated skin factors. Both mechanical
and chemical means have been used in the field to clean up
DIF mud cake. Chemical means include acids, oxidizers,
chelating agents, enzymes or a combination of these chemicals,
which are used to dissolve the CaCO3 bridging materials in the
mud cake. Achieving uniform mud cake removal across long
horizontal sections with open hole completions using rapid
reacting chemicals, such as HCl acid, is a challenging task8.
Although the use of harsh chemicals, such as HCl acid, is
widespread, there are many concerns and limitations associated with their use, especially in high temperature formations
since strong acids have high corrosion rates that are difficult to
inhibit at high temperatures9. In addition, their high reaction
rates with CaCO3 result in the degradation of mud cake
mainly at the point of acid introduction. This promotes a rapid
and localized reaction, which results in uneven removal of the
mud cake, leaving the rest of the formation untreated.
The main objectives of this study are to: (1) evaluate several
systems for the removal of OBM mud cake, (2) explore the
compatibility of LF reservoir oil with HCl acid, and (3) design
an effective non-damaging acid recipe to stimulate the acidsensitive LF formation.
PROCEDURE AND EXPERIMENTAL WORK
Materials
Representative heavy oil samples from the LF reservoir were
used to conduct all the acid-oil sludge and emulsion experiments. Solutions of 20 wt% HCl acid were prepared using analytical grade 37 wt% HCl acid and distilled water with a
resistivity greater than 18ȉ.cm at room temperature. The antisludge, iron control and demulsifier additives were supplied by
a service company and were used as received for the sludge
and emulsion tests. Preflush, surfactants and micro-emulsion
chemicals were used as received for the mud cake removal
tests. The surfactants were supplied by a second service company, while the micro-emulsion chemical system was supplied
by a third service company. The micro-emulsion system contains solvents, surfactants and acetic acid, Table 1. A mixture
of two solvents — paraffin dissolver and tar dissolver — surfactant and diesel was supplied by a fourth service company
and was used for the sludge and emulsion removal tests. Table
2 shows the conventional asphaltene/sludge removal treatment
recipe.
Component
Amount (vol%)
Fresh Water
63
Surfactant
21
Solvent
5
Acid Corrosion Control
1
Acetic Acid
10
Table 1. Micro-emulsion recipe for mud cake removal
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Component
Amount (vol%)
Paraffin Dissolver
30
Tar Dissolver
30
Diesel
38
Surfactant
2
Table 2. Typical paraffin dissolver and tar dissolver sludge treatment
T
X-Ray Diffraction
X-ray diffraction (XRD) was performed on core samples to
gain knowledge about the mineralogy of the reservoir rock.
The samples were crushed to fine powder using a mill. The
clay-size fractions of the sample were separated and air dried
on a glass slide. The air-dried glass slide was glycolated in a
desiccator containing ethylene glycol at 140 °F in the oven.
The identification of the crystalline phases was analyzed. Subsequent semi-quantification of XRD data was done using the
Rietveld Refinement method. The clay-size material, < 2 microns equivalent spherical diameter, was separated from the
larger size particles by sedimentation techniques.
Environmental Scanning Electron Microscope (ESEM)
Micro-structural characterizations, in terms of porosity, pore
size and the presence of clay and foreign materials in the pores,
are important in understanding the behavior of reservoirs. In
addition, such investigations help in selecting the right acidizing treatment for the formation.
In this test, the environmental scanning electron microscope
(ESEM) analytical techniques were utilized with an integrated
ultra-thin window energy dispersive X-ray detector to perform
comprehensive micro-structural characterizations of the core
samples in this reservoir.
The ESEM data are used to identify the minerals in the core,
any materials blocking the pore space, the type of cementing
materials present and also the elemental compositions of the
core plug samples. In addition, the ESEM can indicate any clay
settlement close to the pore throats, which would potentially
block the fluid flow pathways.
The primary goal in this test was to identify the main components of the reservoir core samples and to correlate them
with the XRD results to have a better understanding of the
acid-rock interactions in this reservoir.
Coreflood
A coreflood apparatus was designed and built to simulate fluid
flow in porous media in the reservoir. A positive displacement
pump, equipped with a programmable controller, was used to
deliver fluids at constant flow rates at variable speeds up to
200 cm3/min and at pressures up to 10,000 psi. The pump was
connected to two accumulators to deliver brine or chemical
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solutions. Accumulators with floating pistons rated up to
3,000 psi and 250 °F were used to store and deliver the fluids.
A set of valves was used to control the injected fluid into the
core sample. The core holder can accommodate a core plug
with a diameter of 1½” and a length up to 3”. Pressure transducers were used to measure the pressure drop across the core.
A back pressure regulator was used to control the flowing
pressure downstream of the core, and a second back pressure
regulator was used to control the confining pressures on the
core plug. A convection oven was used to provide a temperature controlled environment. A data acquisition system was
used to collect data from the pressure transducers. Below are
the procedures used to prepare the core for the coreflooding
experiments:
1. The core samples were dried overnight at a temperature
of 212 °F in an oven.
2. The core samples were saturated with formation brine in
a vacuum, then centrifuged to initial water saturation.
3. The core samples were loaded into the core holder, and
confining pressure was applied.
4. A 6% potassium chloride brine was injected in the core
to establish ~100% water saturation.
5. The base permeability to water was measured using a
flow rate of 1 cm3/min.
6. Distilled water was then pumped to test the sensitivity to
clay swelling and migration at flow rates of 2 and 4
cm3/min.
Formation Water/Mixing Water Compatibility
The high-pressure/high temperature (HPHT) aging cell was
used to investigate the mixing water/formation water scaling
tendency. The experiments were performed at a temperature of
240 °F. The pressure was maintained at 500 psi using nitrogen
gas. The duration of the water compatibility test was 24 hours.
The ratios of the mixing water/formation water were 10/90,
25/75, 40/60, 50/50, 75/25 and 90/10. In addition to the lab
experiments, a scale simulation was run to predict the scaling
tendency of the two water types. The simulation included
water compositions and reservoir properties.
SARA Analysis
The four SARA fractions are: (1) saturates — iso- and cycloparaffins, (2) aromatics — containing one or more aromatic
rings, (3) resins — polar substituents miscible with heptanes or
pentane, and (4) asphaltenes — polar substituents insoluble in
an excess of heptanes or pentane. The SARA analysis is a
method for characterizing heavy oil based on fractionation,
where a heavy oil sample is separated into smaller quantities,
or fractions, with each fraction having a different composition.
Fractionation was based on the solubility of hydrocarbon components in the various solvents used in this test, with each frac-
tion consisting of a solubility class containing a range of different molecular weight species. Gravity-driven chromatographic
separation (adsorption chromatography) was used to determine the fractions of the reservoir’s oil10.
Gravity-driven chromatographic separation is conducted as
follows:
1. Prepare the crude oil sample.
2. Use n-hexane to separate the asphaltenes.
3. Use two columns to separate the rest:
• An attapulgite clay-packed column adsorbs the resins.
• A column packed with activated silica gel separates
the aromatics from the saturate fraction.
4. Use a 1:1 mixture of toluene and acetone to recover the
resin fraction from the clay packing.
5. Recover the aromatics by Soxhlet extraction of the silica
gel in hot toluene.
6. Calculate the amount of the volatile components lost
during the process by calculating the weight difference.
Acid-Oil Compatibility
The HPHT aging cell was used to investigate the sludging tendency of the LF oil after it contacted both live and spent 20
wt% HCl acids. The experiments were performed at temperatures ranging from 140 °F to 240 °F. The pressure was maintained at 500 psi using nitrogen gas. Another set of experiments was conducted using the anti-sludge, iron control and
demulsifier additives. The duration of each acid-oil sludge test
varied between 2 to 24 hours. The acid-oil ratio was kept constant for all conducted tests at mixing volume ratios of 1:1.
Each oil sample was filtered, using 100 µm mesh size, before
and after the sludging test. For the spent acid sludging experiments, a HCl acid solution was neutralized with CaCO3 until
the pH reached 3. Another set of sludging experiments was
conducted in the presence of Fe3+. The total iron concentration
in the experiments varied between 0 ppm and 1,000 ppm.
Several tests were conducted to determine the effect of H2S
on the sludge/asphaltene precipitation and its stability. The
H2S tests were conducted using a closed system loop. H2S was
generated by reacting iron sulfide (FeS) with 10 wt% HCl acid
in an erlenmeyer flask; the generated H2S gas was then diverted to a second flask containing live 20 wt% HCl acid and
the LF oil at a 1:1 ratio with iron concentrations ranging from
0 ppm to 1,000 ppm. After exposing the solution to H2S gas,
the H2S was then diverted to a third flask containing cadmium
sulfate (CdSO4) where the H2S was scavenged completely into
cadmium sulfide (CdS). The setup is shown in Fig. 1. The H2S
experiments lasted 2 to 4 hours and the acid-oil was then filtered through 100 µm mesh size to determine the severity of
the sludge/asphaltene.
Removal of Acid-Induced Sludge
The effectiveness of different mixtures of two solvents —
Fig. 1. H2S generation setup used in testing the effect of H2S on sludge/
asphaltene precipitation.
paraffin dissolver and tar dissolver — surfactant and diesel in
removing the acid-induced sludging material from the LF formation was explored. The sludge/asphaltene removal experiments were performed at a temperature of 140 °F and
atmospheric pressure. The ratio of dissolver/sludging material
was kept at 10:1 (mL:g). The duration of all conducted sludging removal experiments was 4 hours.
Mud Cake Removal
The mud cake removal experiments were performed using an
HPHT filter press cell. A nearly 200 mL representative sample
of the oil-based DIF used during LF drilling operations was introduced into the fluid loss cell. Using 3 µm ceramic disks as a
medium, the filtration process was initiated by applying a differential pressure of 300 psi. This filtration process was continued at 240 °F until the fluid loss reached a constant volume,
indicating that a mud filter cake had been built on top of the
ceramic disk. The mud filter cake was then soaked in the acid
treatment for 4 hours under 240 °F and 300 psi. The weight of
the formed mud cake was measured before and after it was
soaked in the clean out treatment acid. The recorded values
were used to calculate the percentage of the cake weight lost
due to its interaction with the clean out treatment acid.
RESULTS AND DISCUSSION
Mineralogical and Rock Analysis
XRD analysis is necessary to screen the rock to eliminate any
possibility of acid-sensitive clays being present, such as excess
amounts of chlorite or illite. The XRD results showed that the
samples consisted of carbonate minerals — calcite and ankerite
— with minor quantities of clay minerals — kaolinite, I-S and
illite — as well as sand — quartz — in some of the samples.
Table 3 gives the chemical compounds of these minerals and
others common in the oil industry. Table 4 shows the bulk
mineralogical composition of several core plugs from this
reservoir. The data indicated that calcite was the most domiSAUDI ARAMCO JOURNAL OF TECHNOLOGY
FALL 2015
Calcite
Ankerite
Dolomite
Illite
Kaolinite
Quartz
Pyrite
CaCO3
Ca(Fe,Mg,Mn)
(CO3)2
CaMg(CO3)2
(K,H3O)(Al,Mg,Fe)2
(Si,Al)4O10[(OH)2,(H2O)]
Al2Si2O5(OH)4
SiO4
FeS2
Table 3. Chemical composition of minerals in the formation samples
Plug
Calcite
Ankerite
Illite + IS
Kaolinite
Quartz
Grain Density
#
wt%
wt%
wt%
wt%
wt%
g/cm3
1
70
16
7
4
3
2.75
2
80
12
4
2
2
2.75
3
95
0.5
0
0
4.5
2.75
4
91
9
0
0
0
2.75
5
98
1
1
0
0
2.75
Table 4. XRD results
T
nant mineral in the samples, with wt% ranges between 70%
to 98%. The second dominant mineral was dolomite, with 1
wt% to 16 wt%. Clay minerals, including total clays of mixed
layers of illite-smectite, illite and kaolinite, were also detected
in the same samples, reaching up to 14 wt% in the extreme
case. Some core samples did not have any clay in them.
Figure 2 contains the ESEM images confirming the presence
of CaCO3, mainly in the reservoir core sample. In addition,
Fig. 2 shows that the pore throats are clay free in the reservoir
core sample. Multiple solubility tests were conducted following the XRD analysis to confirm the abundant presence of
CaCO3, Fig. 3.
cm3/min for 90 pore volumes at each rate. The pressure drop
was measured between the inlet and the outlet of the core sample. The pressure drop showed no change while pumping distilled water at 2 cm3/min. The rate was increased to 4 cm3/
min, and the pressure drop still did not show any significant
spikes or changes. This indicated that the clays in the core
Clay Swelling and Migration
Coreflood tests were run several times to test the sensitivity of
the samples to clay swelling and migration. Figure 4 shows the
coreflood graphs. The core was first flooded with a temporary
salt clay stabilizer to determine a base permeability. The core
was then flooded with distilled water at 2 cm3/min and 4
Fig. 3. Solubility test result indicating a high amount of CaCO3 in the reservoir
core sample.
Fig. 2. ESEM analysis confirming the presence of CaCO3 mainly in the reservoir,
with the pore throats being clay free.
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Fig. 4. Coreflood results indicating no damaging effects from clay swelling
and migration.
Parameter
Ca
Mg
Cl
Fe
K
Na
Sr
SO4
Mixing water
200
2
100
10
5
20
0
50
37,000
6,700
122,500
30
1,000
34,000
1,400
480
Formation water
Table 5. Comparison between mixing water and formation water
samples didn’t have major swelling or migrating effects that
would hinder the flow of hydrocarbons.
asphaltenes are unstable, while 0.7 < CII < 0.9 indicates a
potential asphaltene problem. CII < 0.7 indicates that the
Scale Analysis
Scale formation in the reservoir rock could block the pores and
hydrocarbon pathways, which hinders the flow of hydrocarbons to the wellbore. Water compatibility is a factor in scale
formation, between the mixing water used to mix the acid system and the formation water encountered while pumping the
acid treatment. This makes it very critical to test both water
compositions for scaling compatibility. Table 5 shows the comparison between the mixing water and formation water.
Simulation runs were performed to determine the critical
mixing ratios at which scale could occur; Figure 5 shows the
results. The simulation indicated some minor scale precipitation, but the amount of scale precipitation was below the
threshold of scale quantities that would hinder the flow of hydrocarbons to the wellbore. To confirm this, seven samples
were tested for compatibility in the lab at different ratios of
mixing water/formation water — 10/90, 25/75, 40/60, 50/50,
75/25 and 90/10. The samples were prepared and kept in a
convection oven for 24 hours at reservoir temperature. The
compatibility results indicated no scale precipitation issues
between the mixing water and formation water, Fig. 6.
SARA Analysis
SARA analysis was conducted on the crude oil to determine
the amount of saturates, aromatics, resins and asphaltene in
the oil. Several coefficients can be calculated to determine if
the oil is problematic in terms of asphaltene/sludge precipitation. One of the most common misconceptions in diagnosing
asphaltene problems is that calculating the resin to asphaltene
ratio is enough, basing the diagnosis solely on this number.
This method is not very accurate because many other factors
besides resin content contribute to the stability of asphaltenes
in crude oil. One coefficient was found to be very helpful in
taking many components of the oil into consideration prior to
determining the asphaltene stability. Equation 1 is the coefficient of the CII:
(1)
High resin and aromatic content help keep the asphaltene
stabilized in the oil, preventing it from precipitating out and so
hindering the oil flow. High saturates content, in contrast,
destabilizes the asphaltene. CII > 0.9 indicates that the
Fig. 5. Mixing water/formation water simulation results indicate very minimal
scale with no issues of hindering the flow of hydrocarbons.
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Fig. 6. Mixing water/formation water compatibility tests 1 through 7 at 10/90,
25/75, 40/60, 50/50, 60/40, 75/25 and 90/10 ratios, respectively, indicating no
scaling issues.
Saturates
Aromatics
Resins
Asphaltenes
CII
30.4
8.1
1.2
1.6
60.3
Table 6. SARA analysis
T
asphaltenes are stable in the oil11. The CII calculated for the
LF oil is 1.6, which indicates problematic oil in terms of
sludge/asphaltene precipitation. Table 6 shows the SARA
analysis results and CII calculation.
performed in the presence of Fe3+ at 240 °F for 24 hours. Figure 8 also depicts the amount of sludge/asphaltene precipitation after LF oil was mixed with live and spent 20 wt% HCl
acid as a function of Fe3+ concentration. The amount of
sludge/asphaltene precipitation in the acid-oil mixture clearly
increased in the presence of iron. For example, in the 100/100
mL mixture of LF oil/live 20 wt% HCl acid, the amount of
sludging material increased from 6 g to 8 g when the Fe3+ concentration was increased from 0 ppm to 1,000 ppm. Similarly,
the amount of sludge in the LF oil/spent 20 wt% HCl acid
mixture increased from 8.5 g to 12.5 g when the iron concentration was increased from 0 ppm to 1,000 ppm. In addition
to sludge/asphaltene precipitation, it was found that the LF oil
formed a stable emulsion when it was mixed with 20 wt%
HCl acid. The stability of this emulsion mainly depended on
the pH of the acid solution, the presence of Fe3+ and time.
Figures 9 and 10 show the percentage of acid separated
from the LF oil and acid emulsion as a function of time and
Fe3+ concentration for both live and spent 20 wt% HCl acid,
respectively, at 140 °F and 24 hours. The maximum percentage of separated acid for both live and spent 20 wt% HCl acid
Acid-Oil Compatibility
Several compatibility experiments were performed to assess the
LF oil tendency to form a sludge or emulsion due to its mixing
with live and spent 20 wt% HCl acid. The experiments were
conducted using a 1:1 acid-oil mixing ratio at 240 °F and 500
psi for 24 hours. Filtering using 100 µm mesh size revealed
heavy sludge/asphaltene precipitation when the LF oil was in
contact with both live and spent 20 wt% HCl acid, Fig. 7. The
amount of sludge material was more in the mixture with spent
HCl acid; for example, nearly 6 g and 8.5 g of sludge material
precipitated out of 100 mL of the LF oil when it was mixed
with 100 mL of live and spent 20 wt% HCl acid, respectively,
Fig. 8 (far left).
Another set of LF acid-oil compatibility experiments was
Fig. 7. Asphaltenes/sludge precipitation after mixing LF oil with both live and
spent 20 wt% HCl acid at 240 ºF for 24 hours.
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Fig. 8. Amount of sludge/asphaltene after mixing LF oil with live (white bar) and
spent (black bar) 20 wt% HCl acid as a function of Fe3+ concentration at 240 ºF
for 24 hours.
Fig. 9. Percentage of acid phase separated out of LF oil/live 20 wt% HCl acid
emulsion at 1:1 mixing ratio and 140 ºF.
Fig. 10. Percentage of acid phase separated out of LF oil/spent 20 wt% HCl acid
emulsion at 1:1 mixing ratio and 140 ºF.
reached only 40% of the present acid amount in the LF oil and
HCl acid emulsion. Compared to live 20 wt% HCl acid, the
LF oil formed a more stable emulsion with spent 20 wt% HCl
acid. The maximum percentage of separated acid was reached
after nearly one hour for the spent 20 wt% HCl acid/LF oil
emulsion compared to only 10 minutes for the live 20 wt%
HCl acid/LF oil emulsion. In addition to the pH value of the
acid solution, it was found that the presence of Fe3+ stabilized
the LF acid-oil emulsion.
The presence of Fe3+ up to 1,000 ppm had no effect on the
stability of the LF oil/spent 20 wt% HCl acid emulsion. For
example, the percentage of acid separated from the spent 20
wt% HCl acid/LF oil emulsion after nearly one hour remained
constant when the Fe3+ amount was increased from 0 ppm to
1,000 ppm. In contrast, the presence of Fe3+ had a significant
impact on the stability of the LF oil emulsion with live 20 wt%
HCl acid. The percentage of acid phase separated from that
acid-oil emulsion dropped from 40% to 0 ppm when the Fe3+
concentration increased from 0 ppm to 500 ppm.
Furthermore, several H2S experiment results indicated that
a H2S and iron combination stabilized the sludge/asphaltene.
Figure 11 shows the result of filtering the acid and oil after exposing it to 1,000 ppm iron and low concentrations of H2S for
4 hours. The majority of the fluid failed to pass through the
100 µm mesh size, which indicated that the sludge thickness
became more severe due to the combined effect of the H2S and
iron on the sludge/asphaltene.
It is evident from the above results that the LF oil forms
sludging material and a stable acid emulsion when it is in contact with 20 wt% HCl acid, especially in the presence of Fe3+.
Therefore, demulsifier, anti-sludge and iron control acid additives were used in further tests. Citric acid, an iron control
agent, was used at 20 lb/gal to chelate nearly 2,500 ppm of
Fe3+. The concentrations of both demulsifier and anti-sludge
agents were varied until no sludge/emulsion occurred when 20
wt% HCl acid was mixed with the LF oil. Figures 12 and 13
show that adding demulsifier agent at 5 gpt, anti-sludge agent
Fig. 11. Oil was run through 100 μm mesh size, then the acid-oil sludge mix that
was generated in the presence of H2S and 1,000 ppm iron was poured on the
mesh, following that, hot water was poured on the mesh, and the remaining
material is thick sludge precipitation.
Fig. 12. Effect of adding different concentrations of demulsifier agent to the acidoil mix (0 gpt to 15 gpt).
at 5 gpt and iron control agent at 20 lb/gal was effective in
preventing sludge precipitation and emulsion formation when
the LF oil was mixed with 20 wt% HCl acid at a 1:1 ratio and
at 140 °F.
Asphaltene/Sludge Removal
As mentioned, several LF wells had been previously stimulated
with HCl acid without demulsifier and anti-sludge additives.
The wells ceased to flow after the stimulation treatments.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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Fig. 15. Solubility of LF acid-oil sludge in different solvent recipes at a 1:10
solid:liquid ratio for 4 hours.
Fig. 13. HCl acid (20 wt%)/LF oil mixture at 1:1 ratio and 140 ºF for 24 hours:
(a) without additives, and (b) with demulsifier, anti-sludge and iron control agents.
Results indicated the high likelihood that the stimulated wells
had been damaged with asphaltene/sludge precipitation due to
the incompatibility of HCl acid and LF oil. Therefore, several
solvent formulations were tested to find the most effective
aphaltene/sludge removal recipe. Initially, a neat paraffin dissolver solvent was used to dissolve asphaltene/sludge laboratory samples formed by mixing LF oil with live 20 wt% HCl
acid. This solvent was not effective as it only dissolved 20% of
the sludging material after 4 hours at a 1:10 solid:liquid ratio
and 140 °F, Fig. 14.
Further tests explored the effectiveness of several recipes of
two solvents — paraffin and tar dissolver — surfactant and
diesel in terms of removal efficiency and cost effectiveness,
Figs. 15 and 16, and Table 7. It was found that paraffin dissolver/surfactant/diesel at a volume percentage of 30/2/68,
respectively, is the most economical and effective recipe to
remove the acid-induced sludge of LF oil. It removed more
than 90% of the LF sludge after a soaking time of 4 hours at
240 °F, Fig. 17.
Mud Cake Removal Treatment
Table 8 shows the DIF mud recipe used to drill the pay zone.
To effectively remove the generated OBM cake, different
Fig. 16. Paraffin dissolver/tar dissolver/surfactant/diesel combinations of (a)
30/30/2/38, (b) 30/20/2/48, and (c) 30/10/2/58 at a ratio of 10:1 at 140 °F for
4 hours.
Fig. 14. Paraffin dissolver treatment of LF oil sludging material at a 10:1
liquid:solid ratio at 140 ºF for 4 hours.
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
removal recipes were investigated, Table 9. Two recipes, 1 and
2, consisted of a two-stage treatment: (1) mutual solvent/surfactant, and (2) acetic acid. The first stage utilizes surfactant to
alter the wettability of the mud cake to water-wet, which enables the second stage, the use of acetic acid to dissolve the
mud cake bridging material, or CaCO3 particles.
For the test of recipe 1, an OBM cake weighing 9 g initially
Concentration, vol% Paraffin
Dissolver/Tar Dissolver/
Surfactant/Diesel
Cost ($/bbl)
1
30/30/2/38
1,055
2
90/0/2/8
510
3
30/10/2/58
483
4
30/0/2/68
195
Recipe
service company, was not effective in dissolving the LF OBM
cake. After soaking for 4 hours at 240 °F in 200 mL of mutual
solvent and surfactant-2 each at 10 vol%, there was no weight
loss in the OBM cake. This was followed with the same 10
wt% acetic acid treatment for 4 hours. This stage 2 was also
not effective, indicating that the CaCO3 particles in the mud
cake were still covered with oil, Fig. 19. After tests of these different two-stage treatments, a single-stage OBM cake removal
was investigated. The micro-emulsion system, supplied by a
service company, used in the test consists of fresh water, a surfactant, a solvent and an acid corrosion control, Table 9. It
was found that this micro-emulsion treatment was capable of
dissolving the organic layer and treating the CaCO3 weighting
T
Table 7. Different recipes used to dissolve acid-oil sludge
Components
Removal
Efficiency (wt%)
Stage 1: Mutual Solvent
(10 vol%),
Surfactant-1 (3 gpt)
0
Stage 2: Acetic Acid (10 wt%)
27
Stage 1: Mutual Solvent
(10 vol%),
Surfactant-2 (10 vol%)
0
Stage 2: Acetic Acid (10 wt%)
0
Recipe
1
2
Fig. 17. Paraffin dissolver/surfactant/diesel effect on LF oil sludging material at a
ratio of 10:1 liquid:solid at 240 ºF for 4 hours.
Micro-emulsion System:
was soaked for 4 hours at 240 °F in 200 mL of mutual solvent
and surfactant-1 at 10 vol% and 3 gpt, respectively. The mud
cake was then soaked in 200 mL of 10 wt% acetic acid solution for 4 hours at 240 °F. It was observed that the stage 1
treatment had no effect on the mud cake, while the acetic acid
during stage 2 removed only 27% of the mud cake, Fig. 18.
Similarly, recipe 2, using a surfactant supplied by the same
Component
Fresh Water
63%
Surfactant
21%
Solvent
5%
Acid Corrosion
Control
1%
3
> 95
Table 9. Efficiency of OBM cake removal recipes efficiency
Initial Fresh Mud Properties
Average Properties
Base Oil (bbl)
0.76/0.6
Density (pcf)
Primary Emulsifier (gal)
0.75 – 1
Plastic Viscosity (cP)
16 – 20
< 35
8
Yield Point (lb/100 ft2)
8 – 11.1
18 – 26
6–8
6 RPM Readings
6–8
7–9
0.13/0.25
Gels, 10 sec (lb/100 ft2)
5–7
10 – 12
Organophilic Clay (lb)
6–8
Gels, 10 min (lb/100 ft2)
7 – 10
13 – 15
Low Shear Rheology
Modifier (ppb)
2–3
Gels, 30 min, lb/100 ft2
7 – 10
16 – 22
Secondary Emulsifier (gal)
1.50
FL HPHT 250 °F
(mL/30 min)
4–6
<4
25
Electrical Stability (volts)
250
> 600
CaCO3 “Fine” (lb)
8/15
Chlorides
195,000
190,000 – 200,000
CaCO3 “Medium” (lb)
7/15
Wetting Agent (gal)
1–2
Alkalinity Source (lb)
Organophilic Lignite (lb)
Fresh Water (bbl)
CaCl2 (78%) (lb)
58 – 64
Table 8. OBM used to drill formation
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
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Fig. 18. LF OBM cake treated with recipe 1, (mutual solvent/surfactant #1
followed by 10 wt% acetic acid) at 240 ºF for 4 hours: mud cake (a) before
treatment, (b) after treatment with 10 vol% mutual solvent and 3 gpt surfactant
#1, and (c) after treatment with 10 wt% acetic acid.
be 15 gallons per foot (gpf) — this includes the regular HCl
acid and the diversion acid. Preflush and post-flush are inert
fluids used for formation conditioning. A spacer before the
acid stage should be pumped to displace the completion fluid
away from the wellbore. Preflush and post-flush can be waterbased or diesel-based depending on several factors, such as the
reservoir pressure. In addition, a mutual solvent and surfactant
should be added to the preflush and post-flush. The preflush
should be at least one-third of the main treatment acid volume,
or 5 gpf, and the post-flush volume should be enough to displace all acids away from the wellbore.
The use of any necessary chemical additives, such as the
H2S scavenger, anti-sludge agent, demulsifiers, iron control,
corrosion inhibitor, surfactants, diversion fluids or foams,
should be evaluated on a well-by-well basis.
Chemical QA/QC
Fig. 19. LF OBM cake treated with recipe 2, (mutual solvent/surfactant #2
followed by 10 wt% acetic acid) at 240 ºF for 4 hours: mud cake (a) before
treatment, (b) after treatment with mutual solvent and surfactant #2 each at 10
vol%, and (c) after treatment with 10 wt% acetic acid.
material with acid all in one stage. When a 9 g OBM cake was
soaked in 200 mL of this system, it removed nearly 95% of the
LF OBM cake after 4 hours soaking time at 240 °F, Fig. 20.
FIELD QUALITY ASSURANCE/QUALITY CONTROL
Many factors must be considered to achieve a successful stimulation treatment. Planning the recipe and testing the chemicals
are important. But having a clean, smooth operation application is the real key to a successful treatment. To achieve this,
several procedures must be followed, known as the quality assurance/quality control (QA/QC) procedures. Each stage or
chemical has its own procedure that operators must follow to
check quality and performance. Operational QA/QC is divided
into several parts and discussed next.
Recipe General Guidelines
For matrix acidizing, the total treatment acid volume should
Fig. 20. LF OBM cake treated with recipe 3, (micro-emulsion) at 240 ºF for 4 hours:
mud cake (a) before treatment, and (b) after treatment with micro-emulsion system.
• HCl acid concentration: A titration test must be
conducted to determine the acid wt%.
• Emulsified acid: A conductivity test or a drop test in
water must be completed.
• Iron concentration: Tests of the acid should ensure iron
is less than 100 ppm as excess iron will initiate severe
sludge or emulsion formation.
• Sulfate concentration: Tests should ensure the suflate is
less than 100 ppm, as excess sulfate will form insoluble
CaSO4 scale in the spent acid.
• Equipment: All mixing and transporting tanks should be
clean, flushed and corrosion free.
Acid Flow Back Tests
• To calculate pH and determine the optimum soaking
time.
• To analyze the reaction products and determine the
effectiveness of the acid concentrations.
• To analyze the cations, including iron content, to
determine the proper loading of iron control.
• To look for the presence of emulsions; if the emulsion
did not break, tests are needed to see if higher concentrations of demulsifier are required.
The above guidelines were followed and the necessary tests
were conducted on the wells where the new acid recipe and
removal treatment were applied. Many chemical mixes were
not up to standards and had to be remixed. The mixing water
was often contaminated. In addition, emulsified acid quality
was a major issue due to the low emulsifier concentration and
the inadequate cleanliness of the diesel tanks, Figs. 21 and 22.
Once these quality issues were addressed, the results were very
niques were explored to prevent and treat the HCl acid-induced
emulsion and asphaltene precipitation. Additionally, several removal systems for the LF OBM cake were evaluated. Based on
this study, the following conclusions were drawn:
• LF oil was found to be incompatible with both live and
spent 20 wt% HCl acid. It formed stable emulsion and
asphaltene/sludge at 240 °F.
• The presence of iron aggravates the HCl-induced
emulsion and asphaltene precipitation. A significant
impact of the iron presence was observed in live 20
wt% HCl acid.
• The formation of asphaltene/sludge can be prevented by
using anti-sludge, demulsifier and iron control agents at
concentrations of 5 gpt, 5 gpt and 20 lb/gal,
respectively.
Fig. 21. Samples taken while mixing: (a) Quality of the diesel and emulsifier portion of
the emulsified acid was monitored and the portion was remixed until the fluid was
cleaner, (b) First failed emulsified acid mix, (c) On-site tests to increase the emulsifier
concentration, and (d) Emulsified acid passed drop test after adjustments and remixing.
• The formed asphaltene/sludge was found to be soluble
in a mixture of two solvents — paraffin dissolver and
tar dissolver — surfactant and diesel. Nearly 90% of
the LF asphaltene/sludge was dissolved in a mixture of
30% paraffin dissolver, 2% surfactant and 68% diesel
after 4 hours at 240 °F.
• A micro-emulsion system was found to be effective in
removing the LF OBM cake. More than 95% of the
mud cake was dissolved after soaking for 4 hours at
240 °F.
Fig. 22. Mixing water was sampled in each stage and remixed when the quality did not
meet standards.
• A field operation was successful and resulted in a water
injector injectivity increase of 500% and an oil
producer PI increase of 200%.
ACKNOWLEDGMENTS
Well
Type
PI/Injectivity Increase
1
Injector
500%
2
Producer
200%
Table 10. Field treatments after adjusting recipe
T
The authors would like to thank the management of Saudi
Aramco for their support and permission to publish this article.
This article was presented at the SPE Annual Technical
Symposium and Exhibition, al-Khobar, Saudi Arabia, April 2123, 2015.
successful due to the collaboration between the lab and field
engineers. A power injector well drilled in the LF reservoir
showed an injectivity increase of around 500% after undergoing a stimulation treatment with the new recipe. An oil producer achieved a productivity index (PI) increase of 200%
after the new recipe adjustments and guidelines were applied,
Table 10.
REFERENCES
CONCLUSIONS
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“Formation, Effect and Prevention of Asphaltene Sludges
during Stimulation Treatments,” Journal of Petroleum
Technology, Vol. 17, No. 9, September 1965, pp. 10231028.
The compatibility of LF oil with HCl acid was extensively investigated at different conditions. It was evaluated as a function of the pH value of the acid solution, the presence of iron
and well temperature. Several experiments and different tech-
1. de Boer, R.B., Leerlooyer, K., Eigner, M.R.P. and van
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K.M.: “The Occurrence and Control of Acid-Induced
Asphaltene Sludge,” SPE paper 19410, presented at the
SPE Formation Damage Control Symposium, Lafayette,
Louisiana, February 22-23, 1990.
4. Barker, K.M. and Newberry, M.E.: “Inhibition and
Removal of Low-pH Fluid-Induced Asphaltic Sludge
Fouling of Formations in Oil and Gas Wells,” SPE paper
102738, presented at the International Symposium on Oil
Field Chemistry, Houston, Texas, February 28 - March 2,
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Canada, June 6-8, 1990, 485 p.
7. Fingas, M.F., Fieldhouse, B., Bobra, M.A. and Tennyson,
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Proceedings of the Workshop on Emulsions, Marine Spill
Response Corporation, Washington, D.C., 1993, 11 p.
8. Mason, S.D., et al.: “e-Methodology for Selection of
Wellbore Cleanup Techniques in Open Hole Horizontal
Completions,” SPE paper 68957, presented at the SPE
European Formation Damage Conference, The Hague, The
Netherlands, May 21-22, 2001.
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“Investigation of Retarded Acids Provides Better
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10. Fan, T., Wang, J. and Buckley, J.: “Evaluating Crude Oils
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11. Yen, A., Yin, Y.R. and Asomaning, S.: “Evaluating
Asphaltene Inhibitors: Laboratory Tests and Field
Studies,” SPE paper 65376, presented at the SPE
International Symposium on Oil Field Chemistry,
Houston, Texas, February 13-16, 2001.
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SAUDI ARAMCO JOURNAL OF TECHNOLOGY
BIOGRAPHIES
Tariq A. Al-Mubarak is a Petroleum
Engineer with the Formation Damage
and Stimulation Unit of Saudi
Aramco’s Exploration and Petroleum
Engineering Center – Advanced
Research Center (EXPEC ARC). Prior
to joining this unit, his experience
included work with Saudi Aramco’s Gas Reservoir
Management Department, Schlumberger’s field
engineering/research lab in Louisiana and the
undergraduate research summer program at Texas A&M
University. During these years, Tariq participated in many
projects that included gas field management, matrix
acidizing, damage removal, acid fracturing and hydraulic
fracturing along with attending many stimulation field
QA/QC jobs.
He is an active member of the Society of Petroleum
Engineers (SPE) and strongly advocates for young
professionals to shape the future of the oil and gas
industry. Tariq has published 10 SPE papers and filed one
U.S. patent.
In 2013 and 2014, he received the SPE Best Technical
Paper award, winning first place in both the 3rd and 4th
SPE-SAS technical paper contests.
Tariq received his B.S. degree with honors in Petroleum
Engineering from Texas A&M University, College Station,
TX.
Dr. Mohammed H. Al-Khaldi joined
Saudi Aramco in 2001 as a Research
Engineer working in Saudi Aramco’s
Exploration and Petroleum
Engineering Center – Advanced
Research Center (EXPEC ARC). Since
this time, he has been responsible for
evaluating different stimulation treatments, conducting
several research studies and investigating several
stimulation fluids. In addition, Mohammed was involved in
the design of acid fracturing treatments. As an award for
his efforts, he received the Vice President’s Recognition
Award for significant contributions to the safe and
successful completion of the first 100 fracturing treatments.
Mohammed’s research interests include well stimulation,
formation damage mitigation and conformance control.
He is an active member of the Society of Petroleum
Engineers (SPE). Mohammed has published more than 15
SPE papers and seven journal articles, and has two patents.
In 2011, he received the SPE Best Technical Paper Award,
winning first place in the 2nd GCC SPE paper contest.
He received his B.S. degree in Chemical Engineering
(with First Class Honors) from King Fahd University of
Petroleum and Minerals (KFUPM), Dhahran, Saudi Arabia.
Mohammed also received his M.S. and Ph.D. degrees in
Petroleum Engineering (with First Class Honors) from
Adelaide University, Adelaide, Australia.
Hussain A. Al-Ibrahim is a Petroleum
Engineer with the Formation Damage
and Stimulation Unit of Saudi
Aramco’s Exploration and Petroleum
Engineering Center – Advanced
Research Center (EXPEC ARC). He is
passionate about projects related to
drill-in fluid evaluation and filter cake removal evaluation,
such as evaluating different acid precursors, chelating
agents, micro-emulsion fluids and organic acids. Hussain
has also worked in the area of evaluating different
treatments for condensate banking problems, asphaltene
deposition and scaling potential.
He has been an active part for the last 7 years of a team
that promotes behavioral based safety. Hussain has also
trained many young professionals and technicians on using
various pieces of equipment and conducting different
formation damage-related experiments. He also coauthored
four Society of Petroleum Engineers (SPE) papers.
Hussain received his B.S. degree in Petroleum
Engineering from King Fahd University of Petroleum and
Minerals (KFUPM), Dhahran, Saudi Arabia, and is
currently pursuing an M.S. degree in the same field.
Omar Al-Dajani is a Petroleum
Engineer with the Drilling Technology
team of Saudi Aramco’s Exploration
and Petroleum Engineering Center –
Advanced Research Center (EXPEC
ARC). Upon joining Saudi Aramco, he
started rotating assignments with the
Offshore Drilling Department where he worked as a
Drilling Engineer, writing several oil and gas well drilling
programs as well as witnessing critical jobs in the field.
Omar also worked as a full-time Tool Pusher in the field,
overseeing the safe execution of drilling programs. His next
assignment was with the Northern Area Production
Engineering and Well Services Department as a Production
Engineer assigned to the AFK Production Engineering Unit,
where he ensured the target rate and API blend were safely
and properly met.
Omar received his B.S. degree with honors in Petroleum
Engineering, with a minor in Geology, from Texas A&M
University, College Station, TX. Currently, he is pursuing
his M.S. degree in Geotechnical Engineering and
Geomechanics at MIT, Cambridge, MA.
Majid M. Rafie is a Field Production
Engineer in Saudi Aramco’s Southern
Area Production Engineering
Department. Before he joined Saudi
Aramco, his experience included
working with Baker Hughes in
Houston, TX, as a Field Engineer for
unconventional wells. Majid enjoys working on artificial
lift techniques, such as electrical submersible pumps. He
also is interested in the areas of multistage acid fracturing
and matrix acidizing.
Majid participates in many Society of Petroleum
Engineers (SPE) events and has published three SPE papers.
He received his B.S. degree in Petroleum Engineering
from Texas A&M University, College Station, TX.
SAUDI ARAMCO JOURNAL OF TECHNOLOGY
FALL 2015