Stimulation of Carbonate Reservoirs
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Transcript of Stimulation of Carbonate Reservoirs
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Stimulation of Carbonate reservoirs: Matrix Acidizing and
Hydraulic fracturing
Introduction
The technology used in stimulating carbonate seemed to be overtaken by the sandstone
stimulation technique as sandstone formation have been selectively chosen as hydrocarbon
bearing formation in past years. However, recent technology advancement in oil recovery,
experts claimed that carbonate formation holds about 60% world’s oil and gas reserve. Carbonate
complexity in completion, stimulation and production become hard as its thick pay zone have
extreme permeability ranges (Al-Anzi et al., 2003). This is supported by Guo, Xiao, and Wang
(2014) as this formation susceptible from damage caused by completion and drilling due to the
existence of wide distribution of natural fractures and vugs. The objective of carbonate
stimulation is to effectively treat the productive zone, reducing formation damage and increasing
productivity.
Hydrochloric acid is the most widely used solution to stimulate carbonate formation. It is highly
reactive upon contact with this type of formation and having additional advantage of being
relatively inexpensive and flexible with various conditions. The reaction of this acid with
carbonate formation is rapid and its byproducts are water soluble, hence, easily removed(Sengul
& Remisio, 2002). Nevertheless, rapid reaction between these two cause disadvantages due to
fast spending rate and limit effectiveness of stimulation. As a result, chelating agents are used as
alternatives in case the use of HCl is not possible.
There are currently many techniques being used in stimulating a carbonate reservoir such as
matrix acidizing and acid fracturing. The concept of matrix acidizing is to decrease formation
damage and form additional permeability in case of high positive skin, initially high permeability
and shallow depth of damage whereas acid fracturing is used to bypass damage by creating
fractures and dissolve rock to create extra pathways in case of naturally fractured formation and
heterogeneous formation. These techniques are proven to be reliable as most of the stimulation
for carbonates formation undergo acidizing process predates all well stimulation techniques
(Kalfayan, 2007)
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Literature Review
Carbonate reservoirs are known with their naturally fractured reservoir systems that hold
significant and unpredictable values of permeability difference (Schlumberger, 2014). However,
as 60% of the world’s oil and 40% of the gas reserves are contained in the carbonate reservoirs,
it is unavoidable for someone to attempt to stimulate the current depleting reserves which are
losing their productivity over a certain period (Al-Anzi et al., 2003). In order to have an optimal
production, one must ensure the desired productive zones are treated with suitable stimulation
techniques (Davies & Kelkar, 2007).
As mentioned in the previous section, there are a number of options that are available for acid
treatment which includes soaking and agitation, matrix acidizing and acid fracturing (Sengul &
Remisio, 2002). Among these techniques, the most preferable option for high permeability
damaged carbonate formations (over 50md) will be matrix acidizing whereas acid fracturing is
commonly used in low-permeability carbonate reservoirs (Mader, 1989). In fact, this is also
agreed by Davies and Kelkar (2007) as they mentioned in their research that reservoir zones
consists of long horizontal well possessed variation in petro-physical properties and a stimulation
program must match the needs of the target interval as shown in Figure 1.
Figure 1. Stimulation techniques that should be applied to match various types of intervals.
Adapted from “Middle East & Asia Reservoir Review,” by Davies and Kelkar, 2007.
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On the other hand, Sengul and Remisio (2002) suggested that another method used to dissolve
inorganic scales such as sulfides, fines, debris, metal carbonates which were precipitated out
from crude oil while perforating and producing is known as soaking and agitation. At a later
stage, Samuel and Sengul (2003) further elaborated this technique as wellbore cleanups instead
of soaking and agitation in their research paper. This method, however, does not really stand out
alone since it has already been included within matrix acidizing treatment itself in wellbore
cleanouts (Sengul & Remisio, 2002). They have actually characterized the types of matrix
acidizing treatments into 4 categories which are wellbore cleanouts, near-wellbore treatments,
intermediate matrix stimulation and extended matrix-acidizing as shown in Table 1.
Table 1. Types of matrix acidizing treatments. Adapted from "Applied Carbonate
Stimulation - An Engineering Approach,“ by Sengul and Remiso, 2002.
Matrix Acidizing Treatments Descriptions
Wellbore cleanouts
Treats reservoir by soaking or agitation,
spotting or bullhead treatments with
volume of commonly range from 10 to 25
gal/ft.
Near-wellbore stimulation
Enhances permeability within 2 to 3 ft of
the wellbore with large amount of
treatment range from 25 to 50 gal/ft.
Intermediate matrix stimulation Able to reach 3 to 6 ft of reservoir by using
50 to 150 gal/ft volume of acid.
Extended matrix-acidizing Produces result comparable to hydraulic
fracturing by using 150 to 500 gal/ft.
In carbonates reservoir, matrix acidizing is applied to form new, highly conductive channels
which is also known as wormholes to remove the skin damage or bypass it (Davies & Kelkar,
2007). In fact, acid is injected below the formation parting rate and pressure during the
treatments as mentioned by Sengul and Remisio (2002) in their paper. Hashemi, Sajjadian,
Sajjadian, and Karimi (2011) explained that matrix acidizing is typically used in Iranian
carbonate reservoirs due to the satisfactory outputs and this was supported by Jardim Neto et al.
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(2013) as they expressed the current method is frequently applied for carbonate reservoirs
stimulation in Brazil’s offshore. Several elements such as reservoir temperature, fluid type, and
pumping rate are crucial because these parameters will have direct impact on the reaction
between the formation rock and the treating fluid which is commonly known as acid (Davies &
Kelkar, 2007). To prove the effect of reservoir temperature on the reactivity of carbonates with
acid, Gdanski (2005) had eventually conducted an experiment by comparing 30 limestone and 20
dolomite samples which are later normalized to a reaction order of 0.40 for easy comparison. As
shown in Figure 2, the temperature dependence parameter which is the average energy of
activation, Ea for limestones is 2.5 kcal/mole whereas for dolomites is 5.9 kcal/mole. Another
significant result is that both dolomite and limestone have the same value of energy activation at
200°F.
Figure 2. Normalized and average reactivity of carbonates. Adapted from “Recent
Advances in Carbonate Stimulation,” by Gdanski, 2005.
Although there are a number of acids or fluid types being used in conventional acidizing
treatments such as hydrofluoric – HF, acetic – CH3COOH, formic – HCOOH and sulfamic –
H2NSO3H, yet the most widely used in oilfield is hydrochloric acid, HCl (Sengul & Remisio,
2002). It is claimed that hydrochloric acid exhibits high reactivity with carbonate, cheaper and
versatile. Another reason that it is being used is because most of the products formed from
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hydrochloric acid reactions with the reservoir are easily removed as they are water-soluble. In
fact, HCl can be inhibited easily to control wetting properties, friction pressure and even
allowing subsequent control of penetration.
Despite all the advantages that HCl possesses, it can actually backfire during the entire
stimulation process due to its rapid acid spending at high temperatures (Mahmoud, Nasr-El-Din,
De Wolf, & LePage, 2010). Sengul and Remisio (2002) described that hydrochloric acid reacts
so quickly that the acid spending rate overtook the placement rate which means excess impurities
in limestone that does not react with the acid will end up plugging and reduce permeability. In
fact, Kumar et al. (2005) mentioned this problem as a major challenge in matrix acidizing as the
acid tends to move towards high permeability zone which eventually leaves the low permeability
section to be untreated. This was supported by Mahmoud and Nasr-El-Din (2011) as they
mentioned that the rapid acid spending consumes and wastes a large volume of acid without
really improving the formation permeability.
Another problem expressed by Mahmoud and Nasr-El-Din (2011) is corrosion caused by high
concentration of HCl. It is known that well completion such as tubing, casing and coiled tubing
consist of Cr-based alloy which has protective layer formed by chrome oxide is actually soluble
in HCl. In addition, the corrosion problems become worse at higher temperatures (Mahmoud et
al., 2010). The third problem caused by hydrochloric acid is face dissolution formed at low
injection rate (Mahmoud & Nasr-El-Din, 2011). Fredd and Fogler (1998) said that the face
dissolution ultimately consumes large volume of acid which results in insignificant increase of
formation’s conductivity.
Last but not least, the issue of using hydrochloric acid is the asphaltene precipitation (Mahmoud
& Nasr-El-Din, 2011). They claimed that when crude oil is in contact with acid, asphaltic sludge
will be formed. This is due to the aggregation and precipitation process activated when
asphaltene micelles are depeptized by chemical or mechanical means. This theory was further
explained by Fredd and Fogler (1998) whereby the sludge is capable of plugging the formation
and hence, reduce production after acidizing treatment.
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In order to solve the problems occurred due to the usage of HCl, (Mahmoud et al., 2010)
suggested chelating agent could be the alternatives for HCl to stimulate carbonate reservoirs.
Chelating agents including ethylendiaminetetraacetic acid (EDTA),
hydroxyethylethylenediaminetetraacetic (HEDTA), diethylenediaminetetraacetic acid (DTPA)
are tested to be used as HCl replacement. Fredd and Fogler (1998) elaborated on EDTA, a
chelating agent which stimulates by sequestering the metal components that exist in the
carbonate matrix. This differs from the dissolution mechanism of HCl as it actually does not
require hydrogen ions. Mahmoud et al. (2010) introduced another new chelating agent which is
known as GLDA (L-glutamic acid-N, N-diacetic acid) for an effective carbonate reservoir
stimulation. The benefit of using GLDA is that it has low reaction, low leak off rate and
corrosion rates compared to HCl (Mahmoud & Nasr-El-Din, 2011). Furthermore, wormholes
can be created without washout or face dissolution problems and GLDA can be used for low
injection rate of acid treatment. Figure 3 shows the comparison of different concentration of
GLDA and HCl at 70°F and 250°F at an increasing rate of injection rate. It can be clearly seen
that GLDA with low injection rates at low temperature has low reaction compared to HCl.
However, this is beneficial in terms of volume required to create wormholes and face dissolution.
In contrast, HCl has better performance compared to GLDA at low temperature and high
injection rate. Therefore, Mahmoud and Nasr-El-Din (2011) concluded in shallow reservoir with
low temperature GLDA chelating agent has the most effective stimulation on carbonates
reservoir whereas HCl works well at high injection rate for deep reservoir with high temperature,
provided that the corrosion issues are solved with corrosion inhibitors.
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Figure 3. Performance of GLDA and HCl at low and high temperature. Adapted from
“Challenges During Shallow and Deep Carbonate Reservoirs Stimulation,” by Mahmoud
and Nasr-El-Din, 2011.
The use of fracture acidizing or hydraulic fracturing treatment is quite a common technique for
carbonate reservoir (Gdanski, 2005). The goal is to etch the fracture using HCl treatment to form
conductive wormholes (Davies & Kelkar, 2007). However, to achieve a successful fracture-
acidizing process, three crucial factors which are fluid loss control, reactivity control and
conductivity generation must be equally focused on (Gdanski, 2005; Kalfayan, 2007).
Davies and Kelkar (2007) mentioned that conventional acid fracturing treatments utilize several
stages of nonreactive acids and fluids to prevent fluid loss. This should be a vital cause of failure
for most of the fracture acidizing operations (Gdanski, 2005). Leakoff can be prevented by
increasing fluid viscosity or using fluid-loss additives or even directly utilize a higher-viscosity
fluids (Knox & Ripley). Furthermore, viscosity enhances the width of fractures and enables a
stimulation engineer to slow down the rate of reaction between formation and acid which
ultimately improves the fracture geometry. The most common polymer used to control the
viscosity is crosslinker (Davies & Kelkar, 2007; Gdanski, 2005). It is known that near-spent acid
crosslinker will form high viscosity compound in the matrix after leakoff whereas live acid
crosslinkers provides high viscosity in the fracture.
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The second fundamental issue will be reactivity control (Gdanski, 2005). To achieve an
appropriate reactivity control, the following ideas were actually proposed which are particularly
based on the reactivity of the carbonate itself. For instance, at low temperature reservoir with low
reactivity carbonates, foamed-acid and surfactant gelled can be used. On the other hand,
synthetic polymer gelled acids is preferable when dealing with moderate reactivity carbonates as
it gives a level of reactivity control even though foamed acid and surfactant gelled acids can be
used. Last but not least, high reactivity carbonates with high temperature should be treated with
synthetic polymers.
The final element in determining a good fracture acidizing is the generation of conductivity.
Gdanski (2005) expressed that there are two goals to be met in order to generate a successful
conductivity. The first one will be sufficient carbonate removal followed by removal in an
uneven manner. (Knox & Ripley) expressed that the uneven etching action can actually generates
the fracture flow capacity which enables the production increase rate to be known. In addition to
that, they showed that fracture conductivity are the results of the dissolution of carbonate rock
upon contact with acid. The chemical reaction is shown below:
Various types of rocks can actually have different effects of conductivity generated by acids. For
instance, acid etching in heterogenous rock results in nonuniformity of good fracture flow
capacity as shown in Figure 4. However, for acid etching in homogenous rock, it might not be
good news since low flow capacity is formed as shown in Figure 5.
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Figure 4. Acid etching heterogenous rock. Adapted from “Fracture Acidizing In Carbonate
Rock,” by Knox and Ripley, n.d.
Figure 5. Acid etching heterogenous rock. Adapted from “Fracture Acidizing In Carbonate
Rock,” by Knox and Ripley, n.d.
Different acid stimulation indeed requires several factors to be accounted for. In the end, it really
depends on the reservoir condition and clients demand to choose a suitable acid treatment. The
methodology or procedure might be a decisive factor for one to select the most preferable
stimulation technique for carbonate reservoir and it will be discussed in the next section.
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Methodology
1. Acid Fracturing Method
There are two types of basic acid fracturing method known as Viscous Fingering and
Viscous Acid Fracturing suggested by Kalfayan (2007).
i. Viscous Fingering(Pad) Stages
Figure 6. Stages for Viscous Fingering.
Additional note: Some stages could be repeated to fulfill level of effectiveness
Acidizing using HCI
Fracture the formation using gelled water
HCI acidizing + ball sealer for diversion
Create fracyure geometry by gelled water
Acidizing continuation
Overflush
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ii. Viscous Acid Fracturing Stages
Figure 7. Stages for viscous acid fracturing
15 wt% of HCI for acid fracturing
Formation fracturing using linear polymer-gelled water
Usage of crosslinked polymer-gelled water
28 wt% of emulsified HCI acid
Crosslinked polymer-gelled water
In situ gelled of HCI acid with 28 wt%
Crosslinked polymer-gelled water and linear polymer-gelled water
Allow BHP to drop below fracture closure pressure
Closed fracture acidizing with HCI of 28 wt%
Overflush
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2. Matrix Acidizing Method
This is a general approach suggested by Sengul and Remisio (2002) and Jardim Neto et al.
(2013).
Figure 8. Stages for Matrix Acidizing Method.
Matrix acidizing should give the best effectiveness in several aspects. One of the them is the
location for it to be best conducted in shallow and low-temperature carbonate reservoir in
addition of considerably high fracture pressure as suggested by Mahmoud and Nasr-El-Din
(2011). Instead of usage of HCI, chelating agent could also be used as it gives out low reaction,
leak off rate and rate of corrosion and this was supported by Sengul and Remisio (2002),
Mahmoud and Nasr-El-Din (2011). Compared to propped fracturing, there are some criterias
which need to be highlighted before proceeding with acid fracturing method. Kalfayan (2007)
suggested that acid fracturing should be done with carbonate formation that is predominantly
naturally fractured, heterogeneous formation, high permeability zone and also the oil zone should
be in close proximity to unnecessary water or gas zone.
The pressure of the formation must be higher than the acid used
Acid such as regular HCI is pumped down
Emulsifier or gelling agent may be used to prolong reaction time
Mechanical diversion or chemical diversion may be used
Additives such as inhibitor may be used
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Sengul and Remisio (2002) mentioned that most commonly used acid in the industry for matrix
acidizing is HCl with the concentration of 15 wt%, provided the formation has high porosity of
greater than 35%. That amount of HCl concentration is used to remove carbonate and iron scales
or act as a preflush for the other acids. In case of higher penetration and etching needed, the
concentration of HCl can be increased up to 28 wt%. In acid fracturing, the concentration needed
for HCl is also same with matrix acidzing. In addition, higher acid concentration will
consequently reduce leak-off due to the increase of vicosity (Kalfayan, 2007).
Rapid reactions of HCl acid occurs with carbonate formation. This will result in spending more
of HCI before the intended formation is being treated. Jardim Neto et al. (2013) also claimed that
the acid will react favorably in low resistance formation rather than treating the damaged or low
permeability zone regardless the surrounding temperature and pressure. Sengul and Remisio
(2002) suggested the usage of emulsifiers or gelling agents in action to help increase the reaction
time as mentioned in literature review section.
Diversion is used in carbonate stimulation as the main stimulation acid, HCl caused rapid
reaction and resulted in the formation of dominant wormhole that can leave out the main part
without being stimulated. This diversion will be used as plugging by chemical means such as
chemical diverter and viscoelastic surfactant technology or mechanical means like coiled tube or
ball sealers (Sengul & Remisio, 2002). In the most recent time, polymer-free gelled acid system
which is based on viscoelastic surfactant mixed with HCI acid is used to form wormhole. In fact,
it utilized reversible pH and triggered crosslinker additives to alter the viscosity of the fluid at
critical time during matrix acidizing as explained by Al-Anzi et al. (2003).
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Discussion
From the two main approached studies for stimulation for carbonate reservoirs, we can determine
which type of stimulation techniques to be used based on their different requirements or well
conditions. First of all, it is important to consider that carbonate reservoirs have high reactivity
towards acids. This can be seen from Figure 2 whereby the reactivity of carbonate reservoir has
low activation energies. It is important to note that it is much simpler to get a reaction from
limestone reservoirs than that of dolomite meaning that limestone reservoirs are more sensitive
and will adhere more to reaction with injected acids.
As mentioned before, matrix acidizing is the most favorable method to use in damaged carbonate
reservoirs with the exception of high permeability formation. On the other hand, acid fracturing
increases permeability of carbonate reservoirs that have a lower amount of flow paths. Looking
at matrix acidizing, this is a method specifically used to improve or restore permeability around
the wellbore without fracturing the zone of production.
The acid normally used, as we have discussed, for matrix acidizing is HCl, which is highly
reactive with carbonate formations and therefore causing a challenge in this operation (Fredd &
Fogler, 1998; Kumar et al., 2005). Matrix acidizing requires a very low injection rate but this
process will create wormholes with face dissolution (where most acid will be spent at the surface
of the wellbore) instead of a uniform dissolution. Uniform dissolution is favored because it will
create wormhole that penetrates deeper into the wellbore and form ramified structures or flow
paths which can only occur when the acid is transported at a higher flow rate.
To resolve the challenges brought by matrix acidizing, Sengul and Remisio (2002) suggested that
additives such as inhibitors should be used to avoid corrosion of the bottom whole equipment,
This will deal with the high corrosiveness of HCl. Another solution to this problem highlighted
by Mahmoud et al. (2010) is the usage of Chelating agents, which is preferred due to its
decreased reactivity and low leak off rate. Chelating agents are safer to use compared to normal
HCl and are expected to have better results in terms of spending rate of the injected fluid. Figure
3 in Literature Review section shows the performance of chelating agents versus that of HCL,
which shows that the chelating agents perform better as they are injected at higher rates
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compared to HCl at both high and low reservoir temperature conditions. This is used by
Mahmoud et al. (2010) as the basis to also come to this conclusion.
Another important solution that Sengul and Remisio (2002) suggested is the use of mechanical
diversions or chemical diversions. It is to guarantee that the acid does not simply follow the path
of the least resistance or flow through high permeability zones. In fact, these zones are not the
stimulation target but in order to target the zones with a lower permeability, it is wise to isolate
the higher permeability zones. The other technique used in carbonate reservoir stimulation is
hydraulic fracturing. The goal of acid fracturing differs from that of matrix acidizing which is to
etch the fractures using HCl to create wider flow paths and more fractures by using a higher
pressure than that of matrix acidizing. This system cannot be used near water producing zones as
it will increase water production drastically and reduce the recovery of oil and gas which is the
main resource that is targeted during these operations.
The issues that arise in the treatment hydraulic fracturing are similar to matrix acidizing in terms
of the reactions that the acid caused at reservoir conditions. To solve this, the usage of foamed
acid and surfactant gels are applied for low reactive reservoirs and polymer gels are used in
medium reactivity regions.
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Conclusion
The options that are available for acid treatment found include soaking and agitation, matrix
acidizing and acid fracturing. The most common option of treatment for high permeability
damaged carbonate formations (over 50md) is matrix acidizing, but in the case of low-
permeability carbonate reservoirs acid fracturing is preferred. The most important parameters in
both stimulations are fluid type and pumping rate as they impact directly on the reaction between
the fluid and the formation. Apart from that, the most widely used acid in oilfield is hydrochloric
acid, HCl even though other acids tend to be used as well. It is an undeniable fact that
hydrochloric acid possesses quick acid spending rate which can overtake the placement rate. In
shallow reservoirs with low temperature, we have seen that GLDA chelating agent has the most
effective stimulation on carbonates reservoir. HCl performs better at high injection rate for deep
reservoir with high temperature provided the corrosion issues are solved with corrosion
inhibitors.
To decide on which stimulation to be used, it requires a lot more research than those provided by
a review paper. For a better technical analysis of the effects of these methods, simulation or
experimental comparative work needs to be done whereby both methods are tested under similar
reservoir conditions with the same purpose on which method works best for each reservoir. Most
of the work presented in this paper only focused on one particular method. Even though there are
other comparisons made, they do not provide enough evidence or technical work that would
support the industry on which treatment would serve the best in certain conditions. This is a
recommendation for a future work to be done as a specific demonstration of the differences
would be very productive for the engineers in the field.