oa Investigating the Effect of High Pressures and Temperatures on Corrosion Inhibition for Water-Based Muds

Corrosion is defined as gradual degradation of metal caused by a chemical or electrochemical reaction with its environment. In oil and gas sector, components can corrode at any stage in the life of a field starting from drilling through to abandonment. Recent estimations showed that corrosion costs the oil industry in US yearly around $170 billion. In general, 50% of the operating expenditures in the drilling sector worldwide are for taming corrosion in drill pipe and down-hole equipment. On the other hand, “a corrosion inhibitor is a substance when added in a small concentration to an environment reduces the corrosion rate of a metal exposed to that environment. Inhibitors often play an important role in the oil extraction and processing industries where they have always been considered to be the first line of defense against corrosion” (SLB Glossary). Since corrosion process in mostly due to chemical reaction on the surface of the metal under HPHT condition, water-based mud properties used are hence greatly affected. Mitigating corrosion is a very serious challenge for oil and gas industry as it can't be totally eliminated. Because it is almost impossible to prevent corrosion, it is becoming more apparent that controlling the corrosion rate may be the most economical solution. Thus, the first step to tackle this problem is by determining the cause of the corrosion itself. This is vital as it helps understand the mechanism and the process behind corrosion to suggest more practical and helpful solutions. The corrosion has to have 4 main elements to happen: anode, cathode, electrolyte (Fluid) and external connection. In case any of these elements is absent, corrosion will not take place. In our research, Water based mud is the electrolyte of interest. In general, water helps in speeding the corrosion of metal where the steel itself serves as the external connection. The rate of corrosion depends purely on the grade of the metal and the generated potential due the dry cell effect. Oxygen (O2) which plays an important role in corrosion is only present at the drilling stage and not in the producing formations. Water and Carbon dioxide (CO2) injected at recovery operation can cause severe corrosion of completion string. Also, the presence of hydrogen sulfide (H2S) gases at HPHT has a major role in the dynamics of corrosion. Thus, finding the effect of those elements (O2, CO2 and H2S) in the corrosion process is the main focus of our research. First, the most common element that interfere in the corrosion process is the dissolved oxygen. The reaction of the iron to the oxygen contained in water will form iron rust. The equation below shows the reaction governing the process: 2 Fe⁺⁺+ ½ O2 + H2O = 2 Fe⁺⁺⁺+ 2 OH⁻ . The formed rust is called ferric hydroxide which is characterized as insoluble. While drilling, we will have infinite oxygen as it is an open system operation, thus the corrosion will not cease. The corrosion rate is usually higher when the concentration of oxygen is low thus leading to rust that is impermeable to O2 diffusion compared to that at high O2 concentrations. Second, the presence of dissolved CO2 in water causes the steel to corrode where the rate of corrosion depends mainly on the quantity of CO2 and O2 present as well as temperature and composition of the material. This reaction is weaker than that induced by the presence of O2 for equal quantities. In CO2 based corrosion, carbon dioxide reacts with water to form bicarbonate. The following equation governs the reaction: 2CO2 + 2H2O + 2e- = 2HCO-3 + H2. This equation indicates that the CO2, upon dissolving in water, acts like an acid. Thus, if we have dissolved CO2 and O2 combined in water, stronger corrosion rates will be observed. Third, dissolved H2S can be corrosive if dampness is present. The fact that H2S is highly soluble in water creates a weak dibasic acid, which causes the degradation of iron because of the presence of oxygen. The reaction will be as follows: H2S + ½ O2 = H2O + S. The rate of corrosion is controlled by the concentration of the dissolved gas. If the dissolved H2S is present in low quantities the corrosion will be severe. However, if the concentration of the dissolved H2S is very, it might have reverse effect where it will act to inhibit the corrosion reaction. When both CO2 and H2S are present, while having direct contact with O2, there will sever localized corrosion damage causing the material to crack and fail (Bonis 2014) To go further with the influence of external factors on corrosion rate, we should consider the temperature of the medium. We should not only consider the fact that the reaction rate will increase simultaneously with temperature, but we should account for solubility and viscosity. The solubility of gases in water will decrease with temperature increase as well as the viscosity. However, this is scenario is not true in all cases. For example, when dissolved oxygen is present, the corrosion rate will increase with temperature till a critical point then it will start decreasing with oxygen solubility. If the system is open, the oxygen will escape. Otherwise, the oxygen will be trapped causing the rate of corrosion to increase at high temperatures. Nowadays, the urge to drill deeper to recover larger amounts of hydrocarbons exposes the drillers to High pressure/High Temperature (HPHT) zones. Wells with temperatures greater than 300F and pressures of 1000 psig are classified as HPHT wells. (Bronlee 2005). Moreover, using water based muds (WBM's) will increase the likelihood of a severe corrosion to happen under HPHT conditions. This research is vital to the oil industry as it discusses a problem that has been ongoing for a long time. Corrosion is causing the oil companies a tremendous economic loss. In some cases, and in order to continue the drilling process, the tubing should be changed completely. There have been a lot of experiments on how to mitigate corrosion; however the success rates are still low. Corrosion cannot be inhibited completely; however the aim is to control it. Adding special additives to the drilling fluid or coating the tube with certain chemical are some ways to stop corrosion. The aim of this research is to subject various metal samples of different grades to stress and strain similar to those caused by severe HPHT condition downhole, and compare the results of two main categories: treated samples and untreated samples. The metals are expected to handle more stress when treatment is applied, proving the efficiency of the corrosion inhibitors compare to untreated samples. The challenge is to be able to manufacture an inhibitive chemical that can provide long term resistance as well as durable adherence on the steel. In the laboratory, a drilling water based fluid was prepared using mainly Drill water, Barite and Bentonite. Other additives such as NaCl, Flowzan, Soda Ash and Fine CaCO3 were used as well. Also, different corroding solutions with varying composition were prepared and stored in plastic vessels. The vessels were divided mainly into categories of mediums based on temperate: ambient and HPHT. The samples were prepared specific for each medium. 15 corrosion rings were cut into 4 pieces in Texas A&M University – Qatar machine shop. The initial weight of each sample was measured using a high accuracy electronic balance. The purpose of the Initial weights is to determine the loss after all exposure and treatment operation. This will also help us understand how the condition of each set-up affects the corrosion rate. One sample (1/4 of a corrosion ring) was immersed in each of the two mediums. The variation between the different samples was mainly the size of the corrosion ring, the type of inhibitor used and its concentration. Each sample of mud will contain each size of corrosion ring to determine corrosion accumulation and inhibition based on the size and type of corrosion ring. After approximately 100 hours of exposure, all corrosion rings will undergo the same procedures of inspection for the evaluation of the results. The weight of each sample was recorded before being immersed in the corrosion mediums and after their removal and cleaning From the weight data collected, the corrosion rates was estimated. The initial results showed that when only water based mud is presented without any type of inhibition, the corrosion rate is severe in HPHT medium (4.1 lbs/ft2-year) compared to ambient temperature conditions (2.2 lbs/ft2-year). Moreover, the corrosion rate is less whenever we have a thicker pipe. When adding inhibitor Concor 404 to our media, we see that the corrosion rate diminishes significantly at HPHT for the all corrosion ring sizes compared to base fluid media. On the other hand, using another inhibitor OS1-L will mitigate the corrosion effect in HPHT temperatures to around 1.3 lbs/ft2-year for corrosion ring of size 5.5”. This value is almost triple the rate that we got when using Concor 404. Hence, we deduce that Concor 404 is more effective than OS1-L while using water based mud. In the last batch of samples, Concor 404 and OS1-L were applied together to compare there raltive effect to each other. The inhibition effectiveness was still high under HPHT (around 1.1 lbs/ft2-year) but less than Concor 404 alone and more than OS1-L. It can be deduced that the presence of OS1-L is inhibiting the Concor 404 to perform in full capacity thus lowering the mitigation effectiveness. In general, all three inhibitors with their different combinations work efficiently in mitigating the corrosion. The final decision on whether to choose this inhibitor or the other should be merely based on a thorough economical analysis that includes your needs and takes into consideration your requirements.

Acknowledgement

“This report was made possible by a UREP award [UREP 17 – 133 – 2 - 034] from the Qatar National Research Fund (a member of The Qatar Foundation). The statements made herein are solely the responsibility of the author.”