AC MITIGATION—1: Study stresses need to combine AC mitigation, CP

June 21, 2010
Coordinating AC mitigation with cathodic protection and other aspects of pipeline design, construction, and operation is essential.

Based on presentation to NACE Corrosion 2010 conference, San Antonio, Mar. 14-18, 2010

Coordinating AC mitigation with cathodic protection and other aspects of pipeline design, construction, and operation is essential. Accurate predictive analyses and engineering optimize AC mitigation and can result in considerable cost savings.

The material and construction cost savings for the pipeline discussed in this article by use of a coordinated design approach was $1-2 million. The AC mitigation system should be contractor-friendly, maintenance-friendly, and readily integrated into the pipeline corrosion control program. Operator input in the design is key to making this happen.

Combined AC and DC close-interval survey procedures provide good baseline documentation on the effectiveness of installed AC mitigation and cathodic-protection equipment. Coupon technologies and measurements should be an integral part of pipeline corrosion control and AC mitigation.

This first of two parts discusses mitigation design parameters and results of a network model based on these parameters. The conclusion next week will detail the coordinated design, construction, and commissioning of an AC mitigation and cathodic-protection system.

Background

A 167-mile pipeline parallels and crosses various overhead three-phase high voltage AC power transmission lines with phase-to-ground voltages ranging from 115 to 500 kv. Four power companies own the lines. The accompanying table shows the limits of each power line circuit as well as their steady-state line currents and maximum estimated fault currents.

Some of the three-phase high voltage AC power lines pictured here paralleled the pipeline discussed in this article for nearly its entire length (Fig. 1).

Fig. 1 shows some of the power lines along a portion of the right-of-way. The lateral separation distance between the pipeline and the closest power line varies from 75 to 150 ft. The pipeline crosses under one or more of the power lines 28 times. There were no power line phase transpositions.

Recognizing the complexity of the right-of-way relative to electrical interference, the pipeline owner authorized an engineering evaluation of anticipated AC effects as part of project design. This evaluation included estimating effects on the pipeline without mitigation and developing a mitigation design strategy to safely and reliably operate the pipeline without excessive pipe potentials or unnecessary concern regarding AC-influenced corrosion.

Effectively coordinating AC interference evaluation and mitigation design with the cathodic protection and other design aspects ensured a total systems approach.

A key to successful design was routine information exchange between all parties involved: the pipeline owner's project manager, the pipeline designer, the AC mitigation and corrosion control engineer, the pipeline corrosion control staff, and the four power companies. Communication became particularly critical when pipe alignment changes were necessary during design and as the construction of the pipeline began.

Mitigation design

Technicians collected soil resistivity data along the pipeline right-of-way at nominal 1-mile intervals and at power line crossings. Applying the Wenner four-pin measurement technique (ASTM G57) at each test site determined soil resistivity characteristics.

Soil resistivity data, along with the relative geometry between the pipeline and the different power lines and the power line electrical characteristics including steady-state currents, fault currents and grounding, were input into sophisticated predictive modeling software developed specifically for electrical interference and grounding evaluations.

Primary graphical outputs derived from the software include multilayer and equivalent (deep depth) resistivities used for modeling, and pipe-to-soil potentials vs. distance under steady-state power line operations and under power-line ground fault conditions. Equivalent resistivities derived from the analysis typically measured between 3,000 ohms-cm and 30,000 ohms-cm.

AC predictive analyses investigated pipeline steady-state (peak power transmission) and ground fault effects under the following conditions:

• No mitigation.

• Mitigation consisting of one parallel mitigation conductor connected to the pipe (AC-coupled) along its entire length, with the ribbon positioned in the pipe trench on the side closest to the nearest power line.

• Mitigation consisting of two parallel mitigation conductors connected to the pipe along its entire length, with one ribbon positioned on each side of the pipe in the pipe trench.

One or more parallel mitigation conductors (e.g., steel-cored zinc ribbon) installed at the time of pipe construction is typically the most cost-effective AC interference control strategy for new coated, welded-steel pipelines of substantial length. Up-front engineering analyses determine the extent of parallel mitigation and whether localized "spot" mitigation measures might also be necessary in certain areas.

The benefit of modeling for long pipelines comes in the often substantial cost savings of optimizing the mitigation strategy. The material and construction cost saving for the pipeline discussed in this article was between $1 millon and $2 million.

Simulating concurrent operation of all seven power lines (see table) estimated the normal, steady-state inductive effect on the buried pipeline. For ground fault simulations, evaluation of each of the 500 kv and 230 kv circuits occurred individually, i.e., at any given time there was only one fault on one circuit at one site.

Evaluation of the ground fault effects of the two 115-kv circuits did not happen because of their relatively short lengths of parallelism with the pipeline and because the fault investigations for the other circuits are representative of maximum conditions.

Power-line faults were evaluated through an iterative algorithm simulating a single fault "moving" down the power line. Under this algorithm, the magnitude of fault current and the contribution of current from influencing power substations (and or generating stations) vary as a function of distance.

The AC interference mitigation design engineers evaluated the combined influence of inductive and conductive coupling during a hypothetical fault. The resultant pipe-to-soil potential at any given location is a function of proximity to power line towers in the area, the magnitude and source of fault current, and the local soil resistivity, among other factors.

While higher soil resistivities can sometimes correspond to increased pipe potentials under fault conditions, they can also control the magnitude of fault current emanating from any given tower, thereby reducing potential levels on the pipe.

With higher resistivities comes a greater tendency for the fault current to distribute along the interconnecting overhead shield (sky) wires to multiple towers in the vicinity of the actual fault. For modeling, the fault current was distributed along a total of 21 towers (the faulted tower plus 10 towers upstream and 10 towers downstream).

Discussion with the power companies suggested the probability of a phase-to-ground fault along the pipeline right-of-way was low. Historical data on fault occurrences and the possibility of a fault occurring in the future should always be included in an AC interference analysis since mitigation methods to address faults can often be both more complex and more expensive when compared to those primarily addressing steady-state power line operations. The extent of the fault mitigation employed often becomes a matter of risk management.

Primary influencing factors for steady-state simulations include coating resistance, which was modeled at 400,000 ohms-sq ft, a level representative for fusion-bonded epoxy (FBE) coating on new pipelines. Other factors include relative geometry between the pipeline and power line conductors, and power line operating current.

Power line phase transpositions and locations where the pipeline and power lines cross or diverge from each other typically result in an increase in pipe potential. Power line tower and substation grounding, and subtle variations in soil resistivity, have little effect on steady-state pipe potentials.

Tolerable voltages

The following maximum, tolerable AC pipe-to-soil potentials (local earth) were used to derive a suitable mitigation strategy:

• Steady-state conditions: 15-v touch voltage, buried and exposed locations

• Fault conditions: 4,000-v coating stress voltage, buried and exposed locations

The 15-v steady-state limit is one industry standard for normally exposed pipe. It is included as a guideline in NACE International Standard Practice SP0177, Mitigation of Alternating Current and Lightning Effects on Metallic Structures and Corrosion Control Systems.

Relative to an upper acceptable coating stress voltage during fault conditions, there is no well founded, clearly defined standard or industry-wide practice. For nominal 0.014-in. thick FBE coating, work in 1988 suggests a 3,000-5,000 v maximum coating stress voltage to control coating damage. For the pipeline discussed in this article, an upper tolerable limit of 4,000 v was used based on the low likelihood of a power line fault and other conservative factors in the analysis.

Network simulation

Figs. 2-5 show key pipe-to-soil potential results from network simulations under steady-state and fault conditions, with and without mitigation. As mentioned previously, the steady-state analysis (Figs. 2 and 4) occurred with all seven power lines operating at peak demand, based on information from the power companies.

The fault simulation graphs (Figs. 3 and 5) show the plots of the aggregate maximum potentials determined from a "moving fault" along each of the five simulated power line circuits. Fault data for each circuit allowed derivation of the "maximum" graphs.

Without mitigation, predicted steady-state AC pipe-to-local earth potentials range to 120 v (Fig. 2). Fig. 3 shows predicted AC coating stress and touch potentials under power line fault conditions ranging to 12,000 v. Peaks in steady-state potentials typically correspond to sites where the pipeline and one or more power lines diverge from each other.

The consistently high potential along much of the pipeline under fault conditions is primarily related to a generally consistent separation distance between the power lines and the pipeline. The somewhat higher potentials under fault conditions occur where the pipeline is closer to the power lines, e.g., near crossings, and in the vicinity of the few AC power substations and generating stations immediately adjacent to the right-of-way.

Without effective mitigation, the steady-state and fault potentials would present a clear threat to personnel safety and equipment reliability.

Figs. 4 and 5 show predicted potentials with parallel mitigation, i.e., one or two parallel mitigation conductors periodically connected to the pipe along its entire length. Comparing Figs. 2 and 4 (steady-state analysis), and Figs. 3 and 5 (fault analysis) shows a dramatic reduction in pipe potentials with mitigation. With few exceptions, one parallel mitigation conductor is sufficient to reduce pipeline steady-state and fault potentials to less than the upper tolerable project limits.

Fig. 4 shows little additional value in reducing steady-state potentials along much of the pipeline by adding a second parallel mitigation conductor. For the fault simulations (Fig. 5), the most dramatic reductions in pipe potential resulting from the second mitigation conductor generally occur in areas of lower soil resistivity.

Acknowledgments

The authors acknowledge El Paso Corp. for its approach to AC interference detection and mitigation. Thanks are also due El Paso for permission to publish the information in this article.

The authors

Dale Lindemuth, P.E. ([email protected]) is the director of engineering for Corrpro Companies Inc. in Houston. He holds a BS in electrical engineering from Drexel University in Philadelphia and is a member of NACE International and IEEE. With 31 years of professional corrosion control engineering experience, he is proficient in AC and DC interference mitigation, cathodic protection, and pipeline integrity.
Jerry Creel ([email protected]) is a project manager in El Paso Corp.'s engineering department in Birmingham, Ala. He holds a BS in electrical engineering from the University of Alabama (1977). He is a senior project manager for natural gas pipelines, compressor stations and measurement facilities, including the subject of this paper.

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