Corrosion in the oil and gas industry is one of the critical issues that affect production. Along with its impact on the environment, corrosion is also viewed as an uncontrollable issue within current technology, leading to escalating costs associated with equipment replacement, production losses, contamination, and a decrease in the well’s operational lifetime.

According to a study conducted by the National Association of Corrosion Engineers (NACE), the total annual cost of corrosion in the oil and gas production industry is estimated at $1.372 billion. That figure can be broken down into $589 million in surface pipeline and facility costs; $463 million annually in downhole tubing expenses; and another $320 million in capital expenditures related to corrosion.

An excessive amount of saline water and CO2 corrosion are the two leading causes of corrosion in downhole tubes.

Traditional techniques for dealing with corrosion

To prevent corrosion, different techniques are considered, such as internal lining, the use of corrosion-resistant alloys (CRA), or injection corrosion inhibitors.

However, adding extra thickness to well tubing for corrosion allowance could be expensive in the industry, while lining or injecting corrosion inhibitors are expensive in the long term.

Additionally, the lining has an essential drawback in applying artificial lifts besides its cost, as the tubes become thicker and decrease the fluid production further. Corrosion-resistant alloys (CRA) are another effective option, designed to withstand corrosive environments, thereby eliminating corrosion incidents altogether, although their initial material costs must be considered.

New technique

However, a study titled “Carrier Line Technique for Downhole Chemical Injection in the Oil and Gas Industry”, addressed this critical issue of corrosion in oil production, highlighting its economic and environmental impacts.

This case study focuses on the application of the Carrier Line Technique (CLT) for downhole chemical injection of corrosion inhibitors in three active wells operated by El Hamra Oil Company, which are severely affected by corrosion problems due to a high water cut (W/C) exceeding 95% and the presence of CO2 gases.

The mechanism of CLT involves utilizing produced fluid as a carrier to transport corrosion inhibitors effectively within the wellbore, allowing for controlled delivery to specific zones that may be difficult to reach. This method is particularly beneficial in scenarios where the corrosion rate is exacerbated by increased water formation and CO2 gas predominance.

“Al-Razak in the Western Desert, a high saline reservoir, has high water content compared to oil reaching 80-90% W/C. This can lead to a high risk for corrosion due to saline water along with having a high content of dissolved CO2,” said Ahmed Abdel Salam, Research Assistant at Alexendria University, who participated in the study. “This is a challenge for each material to stand with two types of common corrosion; “water and CO2”, he added.

According to the case study, the Al-Razark field, includes Al#29, Al#38, and NE.AI#14 wells, faced significant challenges due to high corrosion recurrence. This led to reduced productivity, increased replacement costs, and potential environmental impacts, such as oil spills and high diesel consumption.

“We had to find a proper way to avoid the corrosion downhole. Accordingly, we used the carrier line technique (CLT) to drive the corrosion inhibitor to the downhole to make a layer preventing any direct contact from the produced fluid with metal parts. The results are amazing, the occurrence of downhole corrosion is reduced dramatically,” he pointed out to Egypt Oil & Gas.

Result of the CLT technique

The study proved the effectiveness of the CLT in significantly lowering operational costs and enhancing profitability across multiple wells as follows:

Before using any chemical treatments, the operational costs at well 1 accumulated to approximately $396,307.94 over four years, which included production losses, equipment costs, workover unit costs, and fuel consumption. In contrast, after the introduction of downhole chemical injections, the operational costs dropped to about $24,301.37 during the same period, leading to actual profits of $372,006.57.

For well 2, prior to the application of CLT, the cumulative operational costs reached $194,694.80, which included significant expenses for equipment and workover units. After implementing the CLT, these costs were reduced to approximately $26,020.13, resulting in actual profits of $131,503.23 within two years.

Meanwhile, well 3 experienced a reduction in operational costs from $128,075.80 before using CLT to $15,000 after the treatment, yielding actual profits of $168,674.67 within just one year.

Therefore, by employing CLT, the company has been able to significantly reduce corrosion incidents and extend the lifetime of the wells, ultimately leading to substantial cost savings and improved operational efficiency. The technique not only effectively mitigates corrosion but also supports sustainable development goals by reducing the environmental impact typically associated with conventional corrosion management methods.