Iron sulfide (FeS) is one of the most persistent problems in sour production. It builds up in and around pumps and motors, restricts flow, raises pump intake pressure, and slowly drags down production. The standard fix has been to hit it with hydrochloric acid (HCl).
HCl works on the deposit. But at one Permian Basin facility, every acid job came with a cost the treatment was never meant to create: a surge of hydrogen sulfide (H₂S), a forced flare, and a spike in scavenger spend.
Here's how our team changed the chemistry behind the treatment, and what happened when we did.
The Problem With Conventional Acid Treatments
When HCl reacts with iron sulfide, it releases H₂S. At this facility, previous acid treatments caused significant H₂S release both during and after each job. Every event led to the same chain reaction:
-
Forced flaring to manage the H₂S surge
-
H₂S exposure concerns for personnel on location
-
A sharp increase in H₂S scavenger injection to keep outlet concentrations within limits
The result was added emissions, added chemical spend, and added operating cost. The treatment removed the deposit, but it also created three new problems in the process.
Our Approach: Change the Mechanism, Not the Program
Rather than fine-tuning the existing HCl program, Smart Chemical Services looked at why it was failing. The problem wasn't dosage or timing. It was the reaction itself.
So we replaced the conventional HCl cleanout with SIC-1318, a non-acid alkaline chelant treatment designed to remove FeS without triggering the H₂S-generating reaction associated with hydrochloric acid.
Here's how it works:
-
The chelating agent binds the released iron and holds it in solution.
-
The alkaline chemistry keeps the iron sulfide deposit dissolving without the rapid H₂S liberation that comes with acid.
-
Redeposition is minimized, so the iron leaves the system instead of settling back downhole.
The goal stayed the same: remove downhole iron sulfide. What changed was the path to getting there, and that took the H₂S release out of the equation.
The Results: Two Pilot Wells
SIC-1318 was applied to two pilot wells in April 2026. Both were tracked for production, equipment performance, and produced-water chemistry before and after treatment.
Results at a Glance
Pilot Well #1
Production had been declining steadily leading up to the April 21 treatment, with gas and oil at their lowest levels of the period. After treatment, production rebounded quickly and then leveled into a more stable operating trend, without the continued decline seen beforehand.
-
Pump intake pressure dropped 25–30% and held in a more stable operating range.
-
Motor amperage fell 3–5%, with lower and more consistent motor loading.
-
Iron levels confirmed the cleanout. Produced-water iron rose sharply right after treatment, showing substantial FeS dissolution in and around the pump and motor. As production continued, iron returned to a low, stable level, confirming the accumulated FeS had been removed.
Pilot Well #2
The second well had been declining from March into early April and settled well below its first-quarter levels. After the April 24 treatment, oil and gas production rebounded clearly and stabilized at improved levels, while water production held steady.
-
Motor amperage dropped 30%, and amperage variability tightened significantly.
-
Pump intake pressure fell 25–30%, indicating improved downhole flow conditions.
-
Iron levels again confirmed FeS removal, with a sharp post-treatment spike followed by a return to low, stable levels.
Why It Matters: Operational and ESG Benefits
The value of this treatment goes beyond a cleaner wellbore:
-
Safer operations. Controlling H₂S release reduces exposure risk for field personnel during and after treatment.
-
Lower emissions. A 93% drop in flare volume, and no flaring after treatment, meaningfully shrinks the facility's environmental footprint.
-
Lower chemical spend. With less H₂S to manage, scavenger rates no longer have to spike to cover the treatment, opening a path to optimize up to $3.5MM per year in scavenger costs.
-
Better well performance. Lower pump intake pressure, steadier motor loading, and improved oil production point to healthier, more reliable equipment.
In the Operator's Words
"The ability to address scale while significantly reducing flaring provided meaningful operational and environmental benefits. Their team brought a strong technical understanding of both the product and the procedure."
— Permian Basin Engineer
The Takeaway
Sometimes the best way to fix a treatment program isn't to adjust it. It's to rethink the chemistry behind it. By replacing HCl with a non-acid FeS removal strategy, this operator removed downhole iron sulfide while cutting flare volume by 93%, eliminating post-treatment flaring, and improving stabilized oil production by 10–15%.
That's what we mean by Innovation in Chemistry, Value in Service.
Dealing with H₂S and flaring during acid jobs? Our team can evaluate your wells and build a non-acid FeS removal program around your specific conditions. Contact Smart Chemical Services to start the conversation, or download the full case study (PDF).