With any process comes an element of maintenance. The internal combustion engine could not manage excessive operational periods without time taken to clean components and change fluids. The function lingers as a necessity to ensure the expended rate of return. Such a thought process could not be accurate for oil and gas production. Drilling a well does not signify an immediate, highly-populated rate of return on investment. Instead, a barrage of processes must be enacted to gain those desired results.
For over 100 years, acidizing wellbores has long been a partnering process in the oil and gas industry. Acidizing dominates the production arena as the original stimulation technique, which has produced such exponential results that it is still used today. Acidizing extends the life of an oil and gas well and involves injecting or pumping acid into a wellbore, to dissolve or counteract the rocks and sediment that affix themselves to, and line the inside of, the well piping. Since it is an expensive process, companies typically initiate its use when the price of oil warrants such a costly venture.
Considering the current price of oil and the global need to ramp up production, acidizing has once again become a viable strategy for improving production. According to the American Petroleum Institute, acidizing involves three primary categories used to stimulate the wellbore: acid washing, matrix acidizing and fracture acidizing.
Fig. 1. Reaction of organic acid with carbonate core sample. Image: EXPEC ARC.
The art of acidizing has depended on hydrochloric acid (HCI) mixtures to remove scale, rust and other calcium carbonate debris interrupting well flow, Fig. 1. Such an issue is commonly known as restricted flow throughout the industry. Adhering to a cruder definition or analogy, an increased flowrate yields an increase in production, which consequently turns into an increase in profit.
Process innovations and improvements have been developed and tested for several years and are nothing new. The process seems simple and without issue, especially considering the amount of time it has been practiced within the industry. Unfortunately, that is not always the case, and specific factors cause the process to be scrutinized by the public and by the professionals who also employ the tactics.
In his thesis, "A New Organic Acid to Stimulate Deep Wells in Carbonate Reservoirs," Ahmad F. Al-Douri notes that HCL-based stimulation fluids produce less-than-favorable results at high temperatures, due to their fast reactivity, acid penetration, surface dissolution and high corrosion rate. Depending on the formation area receiving stimulation, high corrosion rates can be a significant factor, such as in the Eagle Ford shale, where process equipment can suffer disastrous effects, due to already high corrosion rates found in the wellbore, before even starting a stimulation campaign. Y-strainers and pipelines often succumb to pitting and wall thickness loss. The result is a loss of containment, where fluids exit the pipe uncontrollably.
Fig. 2. Post-core sample with 50% organic acid. Image: EXPEC ARC.
In the paper, "Organic Acids for Stimulation Purposes: A Review," authored by Alhamad et al., the most common organic acids utilized by the petroleum industry are formic, acetic, citric and lactic acids. Alternative organic acids possess acidic characteristics and do not dissociate completely in water, with a donation of hydrogen ions made to water molecules. Known as weak acids, they institute a more delayed reaction with formation rock, thereby decreasing the corrosion rate with steel components, Fig. 2. Adding a corrosion inhibitor to the process further diminishes the corrosion rate.
Formic acids. Formic acid increases wellbore efficiency by extending spend rates while systematically reducing equipment corrosion. This proves even more evident with high-pressure and high-temperature wellbores. The delayed rate of formic acid enables an increased penetration into scale, rust and residue. This has made great strides in improving production and even recovery.
Organic acidizing using formic acid prevails as an effective alternative, primarily when used in conjunction with process equipment suffering the effects of corrosion that even surface when used with inhibiting chemicals. Piping internals continue in process, and existing pitting and wall thickness would generally be exacerbated by HCL but receive a lesser effect of abrasion, due to slower spend rates.
Formic acids further aid their derivatives, such as formite brines, which are the primary components of drilling and completions fluids used in high-pressure and high-temperature drilling situations. Additionally, they can provide a more detailed profile of hydraulic fracturing clay stabilization.
Acetic acids are a welcome alternative to HCL, due to their ability to remain effectively inhibited against nearly all types of steel. When using acetic acid, the exposure time of steel to acid is increased to several days, without negatively impacting piping. This makes it a multifaceted service solution. When considering corrosion incurred, acetic acid and HCL differ. At accelerated temperatures, HCL manages to pit and corrode piping, but acetic acid used at the same temperature has less impact, with only a slight uniform wall thickness removal.
Acetic acid is often selected as a perforating fluid and a kill fluid for wells. It is without viscosity and can maneuver and penetrate at an accelerated pace. Piping littered with scale build-up and minute openings restricting flow can find expedited relief, as acetic acid can penetrate these smaller openings and begin consuming the blockage. This proves possible without degrading the piping itself being cleaned, as it refrains from the same harshness as HCL.
Citric acids have long proven themselves to be multifaceted in the oil and gas industry. Their most common use can be identified on the drilling side, and they are used as a viable tool in reducing the alkalinity, better known as pH, in water-based drilling fluids. This is common in contamination while drilling out cement.
The oil and gas industry focuses on citric acids as an iron sequestrant that is relatively easy to manage, as citric acids are a safer alternative to HCL. Their secure handling also positions them to adjust the pH of fluids used in drilling, completions and waste fluid applications.
With the higher element of safety comes challenges that accompany its use. Citric acid can be expensive, and sometimes supply can dwindle. Because it is a weak acid and safe to handle, it is understandable that it takes increased quantities to match that which is used in HCL applications.
Lactic acids find their use in stimulation strategies, as substances that control iron. When introduced with carbonate, they produce calcium lactate salt. Consequently, it can be utilized as a primary component in drilling fluid mudcake.
While lactic acid is like formic acid when accounting for dissociation constant and calcite dissolution, its effectiveness can be limited because of the reaction-salt solubility. It, however, can hydrolyze with water in solid form to release the acid in situ. Users can find favor with this application, as the in-situ released acid can aid in avoiding corrosion.
Lactic acid precursors serve the hydraulic fracturing application in multizone acid-stimulation treatments, Fig. 3. Due to its use in solid form, the leak-off rate is minimal, because the risk of losing fluid into the formation is reduced. As a result, the acid can be released into a designated area.
Fig. 3. CT scan of post-core flood test. Image: EXPEC ARC.
Selection and application. Like all chemicals and solvents, organic acids have their place in an extensive product and procedure-driven industry, such as in oil and gas. Specific parameters must be considered when determining which acidizing application is suitable for the work. While HCl has been the material of choice and proven effective, new advancements have provided a more effective route to success.
If systems do not fail when acidizing, they will, at some unexpected point down the line. For piping and systems plagued by high rates of corrosion and neglect, an HCl-driven product might cause more harm than good during wellbore stimulation practices. Piping riddled with pitting and diminished wall thickness cannot withstand prolonged doses of HCl.
The correct selection made from the formic acid line can yield the desired results. Because they are weak acids, run time typically increases, which has an underlying effect on the final profit margin set for that particular wellbore. The alternative argument, however, supports the notion that increased run time can eventually induce increased flow. If that is the case, then stimulation proves correct, as production increases after the dose of organic acid is administered. In elementary terms, more prolonged exposure with a weaker product surpasses the results of shorter run times with a harsher product that only enhances the pitting and corrosion that might already have originated in the piping system.
The safety factor associated with organic acids provides a supportive notation to draft their use. They are weaker in structure, which supports the generalization that they are more vulnerable in strength. As a result, they are safer to work with than HCl.
Additionally, organic acids can be directed through neutralization and gain a more acceptable pH. Ranging away from being a dangerous acid, formic acids are much safer to handle and manage when it comes to well optimization and stimulation.
Although organic acids offer an alternative in wellbore stimulation and process piping cleaning, as well as many other facets of the oil and gas industry, HCl-based acidizing still has a place. The run time and condition of the equipment being stimulated must be evaluated to make the correct decision. Pipelines suffering from pitting and wall thickness loss in turns and elbows would more than likely find failure with prolonged exposure to HCl. Process systems conditioned with corrosion inhibiter and biocide regularly can provide a good picture of a cleaner series of piping internals that could be further improved by HCl for short-term use, with some organic acid solvent for extended periods. The decision to determine the appropriate well-stimulation tactic is made through rigorous engineering, testing and a diverse knowledge base.
About the Authors
Dr. Saad Al-Mutairi
Saudi Aramco
Dr. Saad Al-Mutairi is an accomplished petroleum engineer, with over 20 years of experience in reservoir and production engineering. He currently holds the position of Chief Technologist of the Production Technology Division at EXPEC ARC. Throughout his career, Dr. Saad has held various technical and leadership positions within upstream organizations, including roles in petroleum engineering and development, southern area oil operation and exploration. In 2007, he participated in an exchange advanced training program with Chevron USA. Dr. Saad is a distinguished alumnus of King Fahd University of Petroleum & Minerals (KFUPM), where he earned his BS, MSc and PhD degrees in petroleum engineering. Notably, he is the first Saudi to graduate with a PhD degree in the history of the Petroleum Engineering & Geosciences College at KFUPM. Dr. Saad is also a graduate of the Technical Development Program (TDP) in 2014, specializing in CO2 Enhanced Oil Recovery (CO2 EOR). As an active member of SPE, he has served the organization in various capacities during numerous events. His contributions to the field include over 30 journal and conference papers, as well as six filed patents. Dr. Saad's accomplishments have been recognized with several awards, including the SAOO VP Excellence Award in 2018 and two regional SPE awards (Sustainability and Stewardship in the Oil and Gas Industry in 2022, and Middle East Service in 2016).
