Experimental evaluation of corrosion inhibitors for completion fluids in the petroleum production systems

Abstract

Corrosion is the natural and continuous degradation of materials caused by either chemical, mechanical, or electrochemical reactions. Corrosion inhibitors may be added to the completion fluids to address corrosion problems efficiently. It is critical to add corrosion inhibitors in completion fluids, specifically under high-temperature conditions, since the corrosion rate is higher when the temperature is high. This corrosion process limits the life of the drill tools or the oil and gas well and causes formation damage. This research studied corrosion and corrosion inhibition treatments for five completion fluids, namely potassium chloride, sodium chloride, sodium bromide, calcium chloride, and calcium bromide. Phosphate and sulfite-based corrosion inhibitors were individually added to the completion fluids, and their corrosion properties were studied to tackle the corrosion issue. In addition, a mixture of phosphate-based and sulfite-based corrosion inhibitors in completion fluids was studied. Additionally, the experimental results recommend using divalent brines as they were identified as a better medium for lowering corrosion rate and conditions than the monovalent brines. A novel aspect of this study is that the materials leveraged for conducting experiments are also used in actual petroleum production field operations. The experiments demonstrate that the corrosion rate can be efficiently controlled at high temperatures in deeper wells.

Introduction

Well completion process is one of the essential stages in oil and gas extraction. It refers to completing the well to become ready to produce oil and gas (NatGas 2013). In other words, it is transforming a petroleum well from being in the drilling phase to being in the production phase through the installation of production casing and other equipment (Iannuzzi 2011). Well completion can differ in its type based on specific conditions and restrictions. For instance, the selected well completion design should meet the descriptions of the type of hydrocarbon flowing into the wellbore, bottom hole assembly consideration, and tools to be used during the production stage (Repnu 2011). With that being said, well completions range in costs based on the formation type or environment and the location that it is placed (Zendehboudi and Bahadori 2015).

A completion fluid is a liquid free of solids that is fundamental to the completion process of an oil or gas well (Chandrasekaran 2017). These fluids are used for various purposes, including controlling the well pressure and preventing the well from a blowout or preventing the casing from collapsing under overpressure (Fink 2015). Another advantage that completion fluids have is enhancing the well’s productivity by reducing damage to the producing zone and fixing and cleaning the wellbore during the completion phase. These completion fluids are most often brines that are nothing but a mixture of water and salt. The most used brine in the petroleum industry include chlorides, bromides, and formates. This fluid can be of any fluid density or have other flow characteristics used and chemically compatible with the reservoir formation and fluids within (Chandrasekaran 2010).

Completion fluid has several properties and characteristics that may affect its efficiency. Two of these properties are salinity and pH level. High salinity levels in a completion fluid containing inorganic salts like NaCl, KCl, and CaCl₂ will lead to the corrosion of drill tools and casing. This corrosion process is not just restricted to reducing the life of the drill tools or the oil and gas well; instead, it may also cause formation damage (Repnu 2011). Additionally, it is noted that the pH of these fluids falling in the range of 9–11 promotes corrosion avoidance. At the same time, fluids with very high pH must be avoided since they cause clotting of mud and deflocculating issues (Al-Hameedi et al. 2020). Research shows that high pH brines and incompatibility with formation can also cause formation damage (Amani et al. 2015; Al Moajil et al. 2017; Al-Yami and Nasr-El-Din 2009; Bennion et al. 1996; Retnanto and Yamin 1999; Retnanto et al. 2012). Hence, an ideal completion fluid should resist corrosion, operate well under different conditions, and ultimately prevent stress cracking in metals (Houchin et al. 1994).

Forming the completion fluid gets very challenging as they lack solids, but it also experiences more significant problems such as corrosion. By definition, corrosions are destructive material attacks by reacting with the environment, as illustrated in Fig. 1. In oil and gas wells, it is suspected that crude oil and natural gas carry various products that can be corrosive, such as CO₂, H₂S, and free water (Popoola 2013). Corrosions can also be affected by high pressure and temperature due to thermal expansion—and an increase in the temperature will cause a decrease in the brine’s density. The density change will affect the well stability, especially if the brines cannot handle the formation pressure since high temperature and high pressure influence the corrosion rate (Chiriac 2014).

Fig. 1

Corrosion as an electrochemical process (HyperPhysics)

In order to recommend an inhibition treatment, a balance between cost and efficiency should be achieved. Combining both inhibitors will yield an efficiency of 62% at maximum concentrations. (Amani et al. 2016). Oxygen, water, and carbon dioxide play an important role in corrosion. The former is added in the present stage, whereas the latter is injected during the recovery operation, which can result in severe corrosion of the completing string. Under high-temperature high-pressure (HTHP) conditions, H₂S plays a fundamental role in corrosion dynamics.

To further comprehend the corrosion process, it is critical to understand the common elements that play a vital role in this process. The first element is dissolved oxygen. Since steel will be discussed, the reaction of iron with the oxygen dissolved in water results in the formation of rust called ferric hydroxide that does not dissolve in water. This process is described in the equation below:

$${\text{2Fe}}^{ + + } + \, \raise.5ex\hbox{$\scriptstyle 1$}\kern-.1em/ \kern-.15em\lower.25ex\hbox{$\scriptstyle 2$} {\text{ O}}_{{2}} + {\text{ H}}_{{2}} {\text{O }} = {\text{ 2Fe}}^{ + + + } + {\text{ 2OH}}^{ - }$$

(1)

Corrosion continues in the case of an open system because of the presence of infinite oxygen. However, the rate of corrosion depends upon the concentration of oxygen. If the concentration is small, then the corrosion rate is greater, leading to rust-resistant to O₂ diffusion, and vice-versa if the concentration of O₂ is greater.

The second element is CO₂ dissolved in water, enhancing the corrosion rate. However, at equal quantities of both O₂ and CO₂, the reaction is weaker than that induced by the former. When CO₂ reacts with water, bicarbonate is formed, indicating the acidic behavior of CO₂ in water as depicted in the equation below:

$${\text{2CO}}_{{2}} + {\text{ 2H}}_{{2}} {\text{O }} + {\text{ 2e}}^{ - } = {\text{ 2HCO}}^{{ - {3}}} + {\text{ H}}_{{2}}$$

(2)

This bicarbonate formed is prone to cause severe corrosion within the pipes due to its acidic nature, which lowers the pH of the aqueous phase. The increase in corrosive behavior of CO₂ should be bought to control as it leads to severe pitting attacks that are identified as one of the dominant causes of pipeline failures (Kalam et al. 2021). From the description of CO₂ and O₂, it is evident that their reaction with water will result in vigorous corrosion rates.

The third element is H₂S, which helps with corrosion if dampness exists. The chemistry reasoning behind the deterioration of iron in the presence of H₂S is that they are highly soluble in H₂O, which creates a weak dibasic acid in the presence of O₂. This reaction is represented as given in the following equation:

$${\text{H}}_{{2}} {\text{S }} + \, \raise.5ex\hbox{$\scriptstyle 1$}\kern-.1em/ \kern-.15em\lower.25ex\hbox{$\scriptstyle 2$} {\text{ O}}_{{2}} = {\text{ H}}_{{2}} {\text{O }} + {\text{ 2S}}$$

(3)

This rate of corrosion depends strongly on the concentration of gas dissolved. The concentration of H₂S gas is inversely related to the corrosion process. If the amount of H₂S present is meager, the corrosion will be very severe. Still, if it is present in massive amounts, it will have a reverse effect, thereby inhibiting the corrosive reaction.

In the presence of both H₂S and CO₂, alongside having direct contact with O₂, the material will eventually crack and fail due to the severe localized corrosion damage formed (Al-Tammar et al. 2014). Sulfur compounds can show variation under different conditions within the reservoir, for instance, temperature, pressure, and pH. Based on these circumstances, they can provoke or inhibit bacterial growth and corrosion since it is known that sulfur compounds can impact the microbial communities by enhancing microbially dominated corrosion (Basafa and Hawboldt 2019).

Outside of the medium where the corrosion ring is present, an external factor that aggravates the corrosion process is the medium’s temperature. The reaction rate increases with an increase in temperature, and the solubility of gases in water will decrease along with the viscosity. There are limitations to this as well. It is only possible if, for instance, in dissolved O₂, the corrosion rate will increase with rising temperature until it reaches the critical point and starts to decline again with O₂ solubility. However, in the case of an open system, the oxygen will escape, and in the opposing case, the trapped oxygen in the system will cause the corrosion rate to increase at high temperatures.

Corrosion inhibitors are chemical substances that are added to an environment suspected of potentially corroding materials, and it diminishes, delays, or even prohibits the occurrence of corrosion in that environment (Guo et al. 2017; Sherif 2014). Corrosion inhibitors encompass many conveniences as they eradicate corrosion-reducing chemicals that require significant alteration of pH values, eradicate hydrogen-sulfide and oxygen scavengers, and further eliminate aggressive species from the environment. Corrosion inhibitors are classified as cathodic, anodic, or mixed depending on whether they deal with a corrosion process based on cathodic or anodic reactions or a combination of both (Ramezanzadeh and Ramezanzadeh 2021).

Despite the excellent performance that corrosion inhibitors demonstrate concerning corrosion protection, it still introduces a high level of toxicity when utilized and is more expensive and economically inconvenient (Gece 2008). However, due to their previously mentioned attractive conveniences and future potential, extensive research is conducted to further enhance and extend their practicalities beyond their inconveniences. Some of the knowledge gaps of corrosion inhibitors include determining corrosion inhibitors suitable for multiple alloys. Also, the hydrodynamic influence on the functionality of corrosion inhibitors is not fully comprehended. Other pieces of knowledge are insufficient, such as the availability of corrosion inhibitors that deal with localized corrosion specifically, lack of understanding of mechanisms incorporated by corrosion inhibitors in acid cleaning, and preliminary assessment of the toxicity properties of corrosion inhibitors (Farahati et al. 2019).

Inhibitors are substances that can be added to a medium in small concentrations to reduce corrosion by either acting as a barrier by forming an adsorbed layer or retarding the cathodic, the anodic, or a combination of both processes (Palanisamy 2019). Research showed that halogen ions are well-known for inhibiting corrosions when dissolved in acid solutions. Their efficiency follows the order: I- > Br- > Cl- (Palanisamy 2019). Also, it was found that mixed inhibitors (anodic and cathodic) are less dangerous than pure anodic inhibitors, and they can decrease the corrosion intensity. They can control both anodic and cathodic corrosion. Some common inhibitors in this category are silicates and phosphates (Palanisamy 2019). Additionally, adding inhibitors when using low-density formate muds was recommended, as concluded from the metal-coupon-weight-loss method and CGF-II HTHP static corrosion tester (Xiangton et al. 2016).

Optimizing production is known to rely upon the use of completion brines. The completion fluid could either be monovalent brines or divalent brines. In an experiment performed by Aouda and his colleagues, they opted for monovalent brines like NaBr or NaCl because they have high chlorides, sulfates, and carbonates. However, divalent brines like MgCl₂ or MgBr₂ are avoided because they tend to cause severe formation damage due to the in situ precipitation of gypsum, limestone, and sodium chloride (Aouda et al. 2016). The complexity of how certain factors dynamically influence corrosion is presented in Table 1.

Table 1 Factors affecting corrosion

The ultimate objective of this research is to develop further the use of corrosion inhibiting materials in preventing and controlling the rate of degradation by enhancing the inhibition properties. In addition, a careful determination of the applicability of completion fluids is tackled along with their compatibility in petroleum production systems. The project examines different kinds of corrosion inhibitors currently available in the market and different types of completion fluids present in the actual petroleum field operation.

Methodology

The corrosion rings are intended to measure the corrosive effect of completion or drilling fluid. The ring technique is specifically designed for the detection of corrosion types characterized by a metal loss, such as:

• 1. Placement of corrosion test plates in the pipeline to evaluate the corrosiveness of the environment

• 2. Installation and removal time of exposure downhole can be highly informative to corrosion rate determination

• 3. Understanding the type of corrosion and the causes behind it

• 4. Aid in choosing the proper remedial action

The corrosion test equipment must have the following condition to support the process of selection.

• 1. Ring Construction: machined to fit in the toolbox recess at the end of the pin

• 2. Ring Composition: steel should be identical to that of the pipe of the toll used

• 3. Ring Marking: the ring should be stenciled with a serial number for identification

• 4. Ring Preparation: the ring should be shipped to the field in a sealed plastic envelope to prevent initial metal degradation

The schematic illustrated in Fig. 2 below shows the flow process that accommodates the intents of this project.

Fig. 2

Flow process of the corrosion ring test

Figure 3 shows the five completion fluids, i.e., calcium bromide, calcium chloride, sodium bromide, sodium chloride, and potassium chloride.

Fig. 3

Completion of fluids for the research project

The HTHP corrosion tester shown in Fig. 4 is designed to perform corrosion tests under elevated temperature and pressure. The device can heat the sample to 400°F (204.4 °C) and apply up to 5000 PSI (34.5 MPa). Four samples can be tested simultaneously. All wetted components are made of corrosion-resistant stainless steel.

Fig. 4

OFITE HTHP corrosion tester

Operational Specification:

Maximum Pressure: 5000 PSI (34.5 MPa)

Maximum Temperature: 400 °F (200 °C)

Temperature Accuracy:  ± 0.5 °C

Capacity: 4 sample bottles of 150 mL each

Agitator Speed Range: 0–100 RPM

After preparing the completion fluid, the treatment will simultaneously be tested during the test. Incubation of the corrosion ring as the sacrificial item will dictate if inhibition to corrosion is effective. It is projected that the corrosion rate will reduce upon incorporating a specific inhibitor concentration.

Initial actual test

Upon receiving the ring, a visual inspection should be done. If mechanical damage is observed, a “NO” test is required; otherwise, proceed with the test.

• i. Oxygen Corrosion: scrape the scales formed on the ring’s surface using the soft bristle brush. If the scales are attracted to the magnet, a confirmatory test is required, which is the acid test

• ii. CO₂ Corrosion: 3–5 drops of iron sulfide detecting solution on the corroded area forms green discoloration, partially confirming the effect of CO₂

• iii. H₂S Corrosion: 3–5 drops of iron sulfide detecting solution on the corroded area forms yellow discoloration and/or formation of miniature scrambled egg, partially confirming the effect of H₂S

Secondary actual test (cleaning)

Next, is a confirmatory test using 15% HCl acid, following the cleaning process using a soft bristle wire brush. The corrosion inhibitor can be used to minimize further corrosion.

After cleaning, the following are “confirmed if”:

• i. Oxygen Corrosion: pitted appearance was observed on the surface of the ring

• ii. CO₂ corrosion: an effervescence was observed as the reaction of CO₂ gas to HCl and O_2, forming carbonic acid and a generalized/localized kind of corrosion

• iii. H₂S corrosion: formation of yellow discoloration of the solution, evolution of rotten egg-like odor, and spatial cracking in the ring’s surface

Completion fluid formulation and blending

Blending procedure

The weight based on the brine formulation being used is achieved using the table of formulations found in the handbook of different operating companies supplying in the chain. This calculation was done using the salt and water measured in pounds (lb). The concentration of salt in water (sol. Weight %) gives the maximum amount of solute (salt) in the solvent (water) and hence becomes a saturated solution as represented below:

$${\text{Sol}},\;{\text{wt}}\% = \frac{{{\text{salt}}\left( {{\text{lb}}} \right)}}{{{\text{salt }}\left( {{\text{lb}}} \right) + {\text{water}} \left( {{\text{lb}}} \right)}}$$

Table 2 shows the solution weight % and saturation point per weight of each completion fluid at ambient temperature.

• 1. Measure the amount of salt to be used in grams equal to 1 lb/bbl. to the completion of water’s volume in ml. (Note that water density is 1 g/ml)

• 2. Pour the water into a clean container, then turn the mixer on

• 3. Add the salt to the vortex of the solution and wait for 10 min or until all solute dissolves

Table 2 Maximum solubility of salt in water/bbl @ 25 °C

Test procedures

• 1. Material preparation starts with completion fluid, selecting the appropriate sizes and coupons of corrosion plates, availability of salts, and calibrated equipment

• 2. Formulate the brines based on their maximum weight capacity and saturation

• 3. After setting the formulation matrix, separately blend all completion fluid variables. Store all samples in sealed and room temperature conditions to avoid brine crystallization

• 4. Properties such as weight, pH, viscosity, and other important factors will be analyzed

• 5. Each brine will be treated in six different batches based on percentage, type, and ratio

• 6. All samples of the corrosion ring with corresponding completion fluid will then undergo the aging process using the roller oven or directly to the HTHP corrosion tester, depending on the factors and restrictions at high-temperature and high-pressure conditions

• 7. After the test matures, corrosion plates will be recovered and tested right away to prevent further surface deterioration

• 8. The test procedure will follow the NACE SP0775-2013(2.3) and OFITE procedures

• 9. Lastly, after the corrosion rate has been determined, an evaluation of the effectivity of inhibitors will be concluded based on the tabulated results

• 10. Finally, a recommendation will be given if further options must be considered

Results and discussion

Determining the corrosion rate helps in knowing the corrosion category it will belong to, as shown in Table 3, where the corrosion rate will be low if the corrosion rate is in the range of 0.0–5.0 mpy. Table 3 addresses the four corrosion types alongside their corresponding corrosion rates.

Table 3 Corrosion rate conditions

The following equations were used to obtain the required data from experimental results obtained:

$${\text{Weight}}\;{\text{loss }}\left( {{\text{grams}}} \right) = {\text{Initial}}\;{\text{weight}} - {\text{Final}}\;{\text{weight}}$$

(4)

$${\text{Exposure}}\;{\text{Time }}\left( {{\text{hrs}}} \right) = {\text{Date}}\;{\text{and}}\;{\text{Time}}\;{\text{out}} {-}{\text{ Date}}\;{\text{and}}\;{\text{Time}}\;{\text{in}}$$

(5)

$${\text{Corrosion}}\;{\text{Rate}} \left( {{\text{lbs}}/{\text{ft}}^{2} - {\text{year}}} \right) = \kappa \times \frac{{{\text{Weight}}\;{\text{loss}}}}{{{\text{Exposure}}\;{\text{Time}}}}$$

(6)

$${\text{Corrosion}}\;{\text{Rate}} \left( {{\text{milli}} - {\text{inch}}\;{\text{per}}\;{\text{year}}} \right) = \kappa \times \frac{{{\text{Weight}}\;{\text{loss}}}}{{{\text{Exposure}}\;{\text{Time}}}} \times 24.62$$

(7)

$${\text{Inhibitor}}\;{\text{Efficiency}},\;\% = \frac{{{\text{corrosion}}\;{\text{rate}}\;{\text{without}}\;{\text{inhibitor}} - {\text{corrosion}}\;{\text{rate}}\;{\text{with}}\;{\text{inhibitor}}}}{{{\text{corrosion}}\;{\text{rate}}\;{\text{without}}\;{\text{inhibitor }}}} \times 100$$

(8)

Figure 5 displays the collected outcomes of corrosion plates before and after initial and secondary actual tests for potassium chloride (KCl) as an example.

Fig. 5

Corrosion plates in potassium chloride (KCl)

The corrosion plates were inserted in the KCl brine samples with 1.5%, 3%, and 4.5% phosphate-based corrosion inhibitor for about 100 h at 280 °F. After this period, the plates were removed. Figure  5 shows the pictures of the weighed and recorded plates as the initial weight before the testing procedure using 15% HCl and steel wool. After the cleaning process, the plate was weighed and recorded as the final weight.

The duration of exposure, loss of weight, and the K-factor were used to determine the corrosion rates. The value obtained was classified as low, medium, high, or severe corrosion. As shown in Table 4¸without any corrosion inhibitors, the corrosion was severe when the base used KCl and NaCl as they were more significant than 150.0 mpy. However, the severity lowered when the base was NaBr, where it was recorded as high, then further changed to divalent brines, i.e., CaCl₂ and CaBr₂. In the case of divalent brines, the former exhibited high corrosion, whereas the latter was of medium severity based on the range of corrosion rates as displayed in Table 3 above.

Table 4 Corrosion rate for all the completion fluids

Equation (4) through Eq. (8) were used to compute the results, as shown in Table 5 through Table 7 below.

Table 5 Corrosion rate for potassium chloride (KCl) with phosphate-based corrosion inhibitor and sulfite-based corrosion inhibitor

After the exposure, the cleanup of the corrosion plates was followed by weighing these, which allowed for determining the weight loss using Eq. (4) and the corrosion rates using Eqs. (6) and (7). As shown in Table 5, the corrosion conditions are the same using both inhibitors. However, the corrosion rate is lower when a sulfite-based corrosion inhibitor is used than a phosphate-based corrosion inhibitor. Phosphate-based corrosion inhibitor costs $800/drum, and sulfite-based corrosion inhibitor costs $250/drum. Since the corrosion condition is severe when low concentrations of the inhibitors are used, i.e., 1.5% and 3%, it is better to use 4.5% of the inhibitor to achieve a lower corrosion rate. The phosphate-based corrosion inhibitor is costlier than the sulfite-based corrosion inhibitor. Hence, for this case, a sulfite-based corrosion inhibitor is a better inhibitor for KCl as the base sample.

The efficiency of the corrosion inhibitors, phosphate-based corrosion inhibitor, and sulfite-based corrosion inhibitor was compared by plotting the corrosion rates against the concentration of based inhibitors, as shown in Fig. 6. The corrosion rates were lower when a phosphate-based corrosion inhibitor was used as the inhibitor. High corrosion was obtained from the severe corrosion conditions when 4.5% of the inhibitors were used. Using a phosphate-based corrosion inhibitor is technically feasible since it lowers corrosion, but a sulfite-based corrosion inhibitor is a better option in this case.

Fig. 6

Corrosion rate versus inhibitor's concentration for potassium chloride (KCl)

Practically, the cost of a 1.5% of phosphate-based corrosion inhibitor will be the same as a 4.5% of sulfite-based corrosion inhibitor. Considering inhibitors’ efficiency using Eq. (8), at 1.5%, the efficiency of the former is 12.5%, and that of the latter is 36%. Since the difference is enormous, then sulfite-based corrosion inhibitor at 4.5% should be a better option.

The same procedure is done with NaCl as the base sample. Corrosion conditions improve when phosphate-based corrosion inhibitor is used but remain high when it is at 1.5% concentration, and it goes to medium severity at both 3.0% and 4.5% concentration. On the other hand, when sulfite-based corrosion inhibitor is used, the severity remains high throughout different concentrations. Nevertheless, a sulfite-based corrosion inhibitor may be used at a higher concentration to reduce severity conditions, and economically, it is also considered a better option.

When NaBr is used as the base sample, the corrosion conditions reduce from high to medium and low when 1.5%, 3%, and 4.5% phosphate-based corrosion inhibitors are used, respectively. However, in sulfite-based corrosion inhibitor, the corrosion condition is high when 1.5% is added to the sample but lowers to medium when 3% and 4.5% are added. Phosphate-based corrosion inhibitor is a better option since it significantly reduces corrosion rates and is technically feasible. Still, even though the corrosion rates are different, with the severity being the same, economically, a sulfite-based corrosion inhibitor at low concentration will be considered a better inhibitor for NaBr as the base.

The inhibitor efficiency can reach up to 61% using phosphate-based corrosion inhibitors at high concentrations. Economically, the sulfite-based corrosion inhibitor is three times less costly than the phosphate-based corrosion inhibitor. The efficiency of the former is 21% at 1.5% concentration, and that of the latter is 61% at 4.5% concentration. Since the difference is significant, a sulfite-based corrosion inhibitor at 4.5% is recommended.

When CaCl₂ is used as the base sample, corrosion conditions reduce from the medium when 1.5% and 3% of phosphate-based corrosion inhibitor are used but to lower requirements when 4.5% of it is added to the base. The same trend is observed in the case of sulfite-based corrosion inhibitors, as can be seen in Table 6. The corrosion rates are lower for phosphate-based corrosion inhibitors, but very little difference. The sulfite-based corrosion inhibitor will be regarded as a better inhibitor for CaCl₂ as the base sample because the corrosion conditions remain the same in both cases. For phosphate-based corrosion inhibitors, the inhibitor efficiency can reach up to 61%, whereas sulfite-based corrosion inhibitors can reach 52%. At 1.5%, the efficiency of the former is 17%, and that of the latter is 52%. Considering the vast difference, sulfite-based corrosion inhibitor at 4.5% should be a better option.

Table 6 Corrosion rate for calcium chloride (CaCl₂) with phosphate-based corrosion inhibitor and sulfite-based corrosion inhibitor

In Fig. 7, it can be analyzed that the trend observed between the two inhibitors is very close and similar to each other. The sulfite-based corrosion inhibitor is a better choice with this bit of difference because of its feasibility.

Fig. 7

Corrosion rate versus inhibitors concentration for calcium chloride (CaCl₂)

When CaBr₂ is used as the base sample, corrosion conditions reduce from the medium when 1.5% and 3% phosphate-based corrosion inhibitors are used to lower requirements when 4.5% of it is added to the base. The same trend is observed in the case of sulfite-based corrosion inhibitors. The corrosion rates are lower for phosphate-based corrosion inhibitors but with a minimal difference compared with solutions where sulfite-based was added. Hence, a sulfite-based corrosion inhibitor will be considered a better inhibitor for CaBr₂ as the base sample because the corrosion conditions remain the same in both cases.

After the individual analysis of each brine sample with sulfite-based corrosion inhibitor and phosphate-based corrosion inhibitor, the next part of the testing involved an equal mixture of these two corrosion inhibitors. For instance, for a 1.5% concentration of the inhibitor, 0.75% of sulfite-based corrosion inhibitor and 0.75% of phosphate-based corrosion inhibitor were added to the base sample. The same idea was used for adding 3% and 4.5% of corrosion inhibitors. For this study, only NaCl and CaCl₂ were used. When NaCl is used as the base sample, the corrosion rate conditions reduce from high to medium, as shown in Table 7 in the presence of inhibitors. Here, the corrosion condition was severe without any addition of an inhibitor. But as an equal mixture of 0.75% and 1.5% of each inhibitor were added, the corrosion rate dropped to 102–125 mpy, corresponding to high corrosion conditions. But when 2.25% of each inhibitor was added, the corrosion rate lowered to 94.7 mpy, which belonged to the medium corrosion type. The option was somewhat a more acceptable and feasible choice.

Table 7 Corrosion rate for sodium chloride (NaCl) with a mix of 50% phosphate-based corrosion inhibitor and 50% sulfite-based corrosion inhibitor

As shown in Fig. 8, the line corresponding to the 50:50 ratio lies between the pure phosphate-based corrosion inhibitor and pure sulfite-based corrosion inhibitor lines. The result is thus a better illustration of using each inhibitor in equal amounts, thereby enhancing lower corrosion conditions feasibly.

Fig. 8

Corrosion rate versus inhibitors concentration for NaCl with 50–50%

Figure 9 shows the corrosion inhibitor efficiency against the concentration of based inhibitors. This graph quickly illustrates the performance of each inhibitor and the 50:50 proportion in the mixture of phosphate-based corrosion inhibitor and sulfite-based corrosion inhibitor when the same amount of it is added to the NaCl brine. It is known that phosphate-based corrosion inhibitor is three times more expensive than sulfite-based corrosion inhibitor. Figure 9 shows that the efficiency of phosphate-based corrosion inhibitors is very similar to that of the mixture of the two inhibitors. In simpler words, the efficiency of the mixture of 0.75% of each is very close to 1.5% of phosphate-based corrosion inhibitors. Hence, a phosphate-based corrosion inhibitor could be a better option. The same trend is observed when 3% of inhibitor is added. For 4.5% of based inhibitors, the efficiency of phosphate-based corrosion inhibitors is 57%, and that of the mixed inhibitors is 46%. This difference is slightly more significant so that the mixed inhibitor would be more cost-effective and feasible in this case.

Fig. 9

Corrosion inhibitor efficiency versus inhibitors concentration for NaCl with 50–50%

In the case of CaCl₂ used as the base sample, the corrosion rate conditions are better than the former, as the corrosion condition was high without adding an inhibitor. Nevertheless, as an equal mixture of 0.75% and 1.5% of each inhibitor were added, the corrosion rate dropped below 95 mpy, corresponding to medium corrosion conditions. However, when 2.25% of each inhibitor was added, the corrosion rate lowered to 43.52 mpy, which belonged to the low corrosion type. Instead, the outcome was a more acceptable and feasible choice of using inhibitors and a base sample.

The performance of this equal mixture of both corrosion inhibitors is very close to that of phosphate-based corrosion inhibitors. Only 2.25% of each inhibitor was required to obtain a lower corrosion condition. The finding is an excellent choice because using phosphate-based corrosion inhibitors alone was not economically feasible. However, it was highly efficient, as seen in this paper’s earlier sections. The sulfite-based corrosion inhibitor is a better choice with slight differences because of its feasibility.

It was concluded that the efficiency of phosphate-based corrosion inhibitors is very similar to the mixture of two inhibitors, except in the case of 1.5%. For 4.5% of based inhibitors, the efficiency of phosphate-based corrosion inhibitor is 61%, and that of the mixed inhibitors is 58%. This difference is minor, so that the mixed inhibitor would be more cost-effective and feasible in this case. The same is applicable for 3%. However, if the 1.5% case is considered, then the difference in efficiency is approximately 5%. For phosphate-based corrosion inhibitor, it is 17%, and that of 50:50 is 12%, whereas for sulfite-based, it is 11%, all leading to medium corrosion conditions; hence, sulfite-based is economically a better option.

Regarding the uncertainties associated with the results mentioned above, some sources of error can lead to the rise of uncertainties. These can be limitations in the used devices. For instance, the weighing scale measures the weight with an accuracy of 0.01 g, and the temperature accuracy is ±0.5 °C. Moreover, there might be systematic errors with the temperature at which the oven is set, which is an error related to how the oven is calibrated. And lastly, the conditions where the corrosion plates were put in might not be exactly the same as how they are in the petroleum production system, especially when it comes to other gases, humidity, and so on. Hence, the results obtained are considered accurate as it imitates some of the conditions and, most importantly, the HPHT conditions. Concerning the experiments’ repeatability, each set of experiments was done twice. The results show a discrepancy of less than 2%.

Conclusions

This research concentrates on studying corrosion and its respective corrosion inhibition treatments for completion fluids such as potassium chloride, sodium chloride, sodium bromide, calcium chloride, and calcium bromide. Salinity and pH level are two properties identified as affecting the efficiency of the completion fluids. Various corrosion inhibitors were examined for several completion fluids under HTHP conditions.

• 1. Based on the results of this testing, the phosphate-based corrosion inhibitor is the most effective inhibitor at the given concentrations to reduce corrosion

• 2. However, the selection factor in selecting the treatment is not dependent only on the efficiency, rather it is also inclusive of costs. Sulfite-based is less expensive than the phosphate-based inhibitor

• 3. Considering this, a mixture of phosphate-based corrosion inhibitors and sulfite-based corrosion inhibitors seems the most economical and efficient among the tested inhibitors for different completion fluids

• 4. This study involved the use of monovalent and divalent brines. The divalent brines were a better medium for lowering corrosion rate and conditions than the monovalent brines obtained from the corrosion rate and type results

• 5. In the future, corrosion rates under low (180 °F) and medium (230 °F) temperature and pressure conditions will be determined to evaluate the effect of temperature and pressure under varying conditions. The most effective corrosion inhibitor can be chosen based on the results obtained for these conditions