Black Powder: The Conductive Threat to Pipeline Isolation and Cathodic Protection
R. ZIMBRA and N. BANDER, GPT Industries, Denver, Colorado
Electrical bridging, or the electrical connection of otherwise isolated sections of pipeline, is a prevalent issue in the oil and gas industry. Introducing a conductive path to the pipeline system can render cathodic protection (CP) and isolation components ineffective and expensive. But what exactly is the culprit of this problem? This metallic path is largely due to a substance known as black powder, a substance formed in natural gas and crude oil pipelines because of the interaction between hydrogen sulfide [sour gas (H2S)], moisture and iron in the pipe wall. This creates a highly corrosive environment, leading to internal corrosion of the pipeline steel. The highly conductive corrosion product formed is made up of iron sulfide and small quantities of iron hydroxide, iron carbonate and contaminants such as salts, metal debris and liquid hydrocarbons.
The presence of black powder in a pipeline creates increased friction, electrostatically charging the particles as they flow through the pipeline. The charge accumulation allows the particles to become attracted to the inner diameter (ID) of the gasket due to electrostatic adhesion. Friction due to black powder also creates turbulent flow, allowing for more particle collisions. The black powder agglomerates as the ferrous particles are magnetically attracted to one another. This causes buildup on pipeline walls that can restrict flow within the pipeline. Additional velocity is then required to overcome the magnetic and capillary forces holding the particles together. Black powder perpetuates further pipeline corrosion and damage due to its abrasive particles that far exceed the hardness of the pipeline steel itself. Black powder can also contaminate the gas stream and significantly erode the pipe (FIG. 1).
Efforts to remove black powder, such as pigging, can in turn push the conductive particles between flanges, allowing for a metallic path between the flanges. The result is shown in FIG. 2, which indicates a previously isolated flange connection failing to maintain isolation when tested with a radio frequency insulator tester (RF-IT) device. Pigging is especially problematic when the isolating gasket ID is larger than the pipe bore because as the tightly-fitting pig moves down the pipeline, it displaces the black powder. If flange connections have gaskets matching the pipe bore, the black powder will continue to be pushed along the pipeline and eventually be discarded. However, if the gasket ID is larger than the pipe bore, the recess it creates between the flanges provides a crevice for black powder to become tightly lodged in, rendering it inaccessible during further pigging operations.
With the more easily attainable sweet gas reserves becoming depleted, sour gas is more prevalent, leading to electrical bridging becoming increasingly common in modern pipeline systems. Electrical bridging can cause stray current, as previously isolated sections of pipeline become connected, and CP current is allowed to flow freely from one section to the next. This reduces CP system effectiveness and leaves unprotected pipe segments vulnerable to accelerated corrosion. Protective coatings on pipe surfaces may also experience disbondment, causing under-film corrosion. All of these issues can create unnecessary financial strain as the current method to cathodically protect the pipelines becomes ineffective, and pipelines may become damaged to the point of a catastrophic leak or failure.
Field Examples
Case #1: Impact of Gasket Material Selection. One example of electrical bridging in the field involved 6-in. to 12-in. natural gas pipeline with high sour content. The customer conducted trials with glass-reinforced epoxy (GRE) and metal-cored isolation gaskets, but neither was successful at stopping the flow of current from one flange to another. Only after installing an isolation gasket with a polytetrafluoroethylene (PTFE) ID seal did the flow of current completely stop, because there was neither metallic contact nor a material that electrostatically attracted the black powder particles. Additionally, the ID seal matched the flange bore, leaving no room for black powder to accumulate and create bridging between the flanges.
Case Conclusion. This solution utilized an ID seal with a low coefficient of friction that matched the bore. Compared to a metal-cored isolation gasket, the PTFE ID seal also allowed for a longer isolation path. This allowed CP to be effectively utilized and prevent corrosion of their assets.
Case #2: Flange Isolation Performance Matching and Not Matching Bore. A second example involved a field producing more than 20% sour gas with hundreds of isolation points experiencing elevated shorting rates (> 20%). Many of these were not dead shorts but high-resistance, intermittent shorts. Monthly surveys showed frequent changes in RF-IT readings, resistance values and other field measurements, along with significant fluctuations in rectifier output, despite minimal environmental changes that could influence ID drops.
Over several years, the field replaced numerous isolation flange gaskets (IFGs) to ensure the gasket IDs matched the flange bores. Although this improved overall isolation performance, the frequency of high-resistance and intermittent shorts remained, and migration of shorts through locations across the system was documented. Some isolation points consistently maintained strong isolation, while others remained stable, dead shorts with no improvement.
During a turnaround, IFGs from all three categories were removed and analyzed to understand the differences:
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Dead shorts with no change: The gasket ID was larger than the flange bore. Significant corrosion product was present around the gasket ID, predominantly between the 4 o’clock–10 o’clock positions (FIG. 3).
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High-resistance and intermittent shorts: The gasket ID matched the flange bore, and small amounts of corrosion product was observed around the 6 o’clock position (FIG. 4).
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Strong isolation with no historical shorting: The gasket ID was smaller than the flange bore and protruded into the pipe bore (FIG. 5).
Case Conclusion. The study determined that optimal IFG performance is achieved when the gasket ID is specified by the owner/operator to be slightly undersized. This allows the gasket to protrude into the flange bore and create a physical barrier that prevents corrosion products from bridging across the isolation assembly.
Case #3: Monolithic Isolation Joint Performance in Three-Phase Pipeline Service. A pipeline network transporting three-phase fluid with free gas and a water cut exceeding 20% experienced premature isolation failures. Within only a few years of service, 8–12 monolithic isolation joints (MIJs) lost electrical isolation.
Like Case #2, the affected MIJs exhibited high-resistance, intermittent shorting that progressively worsened over time. Multiple fittings were removed and replaced as isolation performance degraded. Upon removal and inspection of the failed MIJs, the following observations were made:
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Significant corrosion product accumulation was present at the 6 o’clock position, consistent with the onsite pipe orientation
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The MIJs were not internally coated or lined
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The supplied isolation gasket was flush with the pipe bore
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Corrosion products had bridged across the isolation interface, creating an electrical short (FIG. 5).
Photographic evidence confirmed that the absence of an internal coating and a flush gasket profile enabled conductive corrosion products to form a continuous path across the isolator (FIG. 6).
Case Conclusion. The failure mechanism was attributed to corrosion product bridging facilitated by unlined internal surfaces and flush gasket geometry. These conditions significantly reduced the effective electrical path length across the isolation interface, accelerating shorting in a three-phase, high-water-cut environment.
For reliable long-term performance, MIJs should always be internally coated or lined. Internal coatings increase the effective electrical path length and reduce the likelihood of conductive particulate or fluid bridging across the isolation assembly.
Solutions
Although the conditions that produce black powder are difficult to control, there are several approaches to mitigating the effects of black powder. A major consideration is isolation component design. Specifying an IFG ID to match the flange bore—or preferably to protrude slightly into the bore—is a recommended practice for mitigating isolation failures in problematic systems. NACE SP0286 permits the gasket protrusion of up to 0.06 in. (1.5 mm). Selecting this simple yet effective practice is highlighted by industry subject matter experts C. Herrera and I. Sokairan in the November 2025 Pipeline & Gas Journal article, where it is identified as one of the most overlooked aspects of specifying pipeline insulation gasket kits.
Similarly, tight machining tolerances ensure that the ID does not leave an exposed area prone to black powder buildup, and that an undersized gasket outer diameter (OD) does not cause eccentricity when installed. However, care should be taken not to protrude the gasket too far into the bore, as this can cause reduced flow, increased turbulence and flow-induced erosion. Additionally, pigs and in-line inspection (ILI) tools may become damaged or stuck, potentially causing damage to the gasket as well. Yet another consideration is material compatibility: while the common GRE-based isolation gasket is stable to many chemicals in the oil and gas industry, its resistance to swelling and volume change is considerably better under compression between flanges than in a free state (FIG. 7).
While GRE-laminated steel can provide effective isolation, the isolating distance from the flange to the metal core of the gasket is very short. Additionally, the cut edges of the GRE present a high coefficient of friction, allowing black powder to become easily stuck to the gasket itself. However, using a non-metallic ID seal with a low coefficient of friction such as PTFE prevents black powder and other particulates from adhering to the gasket ID, while simultaneously increasing the isolating distance. Compared to GRE, PTFE also has the added benefit of being impermeable and holding up to more aggressive media.
Pursuing isolation through the use of an MIJ can allow for long-path isolation, effectively eliminating traveling shorts or the transfer of conductive particles from one area of isolation to another. MIJs also have the added benefit of being hydrostatically pressure tested prior to installation, reducing the likelihood of residual water in the joint for the H2S to react with. It is crucial, however, that the MIJ be internally coated and specified correctly for the type of media and conditions that it will be exposed to.
Remote asset monitoring is yet another valuable tool in avoiding the long-term detrimental effects of black powder and internal bridging. When electrical bridging takes place, the isolating flange will pass isolation tests when initially installed but fail in isolation later during service as the black powder accumulates. By having constant insight into structure-to-electrolyte potentials and monitoring rectifier outputs, electrical bridging can be detected as soon as possible before energy costs from CP add up or corrosion becomes severe. This also reduces the needs for site visits and field surveys that can be costly and inconvenient (FIG. 8).
Takeaway
With reserves only becoming more sour as drilling continues deeper, the presence of H2S and black powder in pipelines is not going away—it is only intensifying. While we may not be able to control the conditions within the pipeline, we can be mindful of isolation component design to set ourselves up for a successful, low-maintenance, long-term isolating solution. Maintaining tight machining tolerances, matching the gasket ID to the bore or protruding into it up to 0.06 in. (1.5 mm), selecting materials such as PTFE ID seals with a low coefficient of friction, utilizing a coated MIJ and remote asset monitoring are all viable options to combat and detect the bridging effects of black powder in pipelines.
About the Author
REBECCA ZIMBRA is a Product Engineer with GPT Industries. She earned a BS degree in metallurgical and materials engineering from the Colorado School of Mines. Zimbra began her career in quality engineering for steel manufacturing before transitioning to research and development engineering, where she performed failure analysis and product validation. Zimbra has been with GPT Industries for 2 yrs, supporting FIK product development and testing. She is an AMPP member and a certified cathodic protection tester (CP1), basic coatings inspector (CIP 1) and former certified weld inspector (CWI).
NICK BANDER is the Director of Engineering and Product Management at GPT Industries and has more than 15 yrs of experience in sealing, isolation and CP. Certified in CP1/CP2 and ASME bolting, he specializes in pipeline integrity and corrosion mitigation.
Literature Cited
1 Sherik, A., et al., Brazilian Petroleum, Gas and Biofuels Institute, “Black powder in gas pipelines,” 2009, online: https://www.osti.gov/etdeweb/servlets/purl/21330217.
2 Kinnear, I. D., “The souring of pipelines,” World Pipelines, August 2024, online: https://www.worldpipelines.com/special-reports/20082024/the-souring-of-pipelines/
3 GPT Industries, “Hydrogen sulfide: The bane of pipelines,” 2025.
4 Khan, T. S. and M. S., Al-Shehhi, “Review of black powder in gas pipelines–An industrial perspective,” Journal of Natural Gas Science and Engineering, July 2015.
5 Herrera, C. and I. Sokairan, “The most overlooked aspect of specifying pipeline insulating gasket kits,” Pipeline and Gas Journal, November 2025, online: https://pgjonline.com/magazine/2025/november-2025-vol-252-no-11/features/why-gasket-bore-size-is-the-most-overlooked-risk-in-pipeline-isolation-systems