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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.