Touch Potentials – Typical Practice Is Not Necessarily Safe

Traditional earth fault limits, earth loop impedances and protection clearance time ‘rule of thumb’ do not always result in safe or compliant systems.

Find out more below or download as a PDF version.

A Typical Underground Example

Touch Potentials


A typical 1000V underground supply system commonly has a 5A earth fault limit. The cables feeding outlet control and the load are often protected by earth continuity relays with a 45Ω pilot earth loop impedance limit. Allowing for the pilot resistance of the installed cable length, could see the total return earth impedance for an earth fault in the load as high as 75Ω.

Worst case touch voltage is: 75/(115+75)*577 = 228V 

Total clearance time for outlet E/L:

  • Earth leakage relay 50 msec (instantaneous)
  • Interposing relay delay 20 msec
  • Breaker/contactor delay 130 msec

= a total clearance time of 200 msec



Not compliant or safeThe scenario is typical of underground practice as the key operating parameters are consistent with values allowed in standards

  • 5A earth fault limit
  • 45 Ohm earth return impedance limit

The potential touch voltage clearance times are to the right of the safe area of the wet area curve (Lp) in AS/NZS4871.


What you need to do

The 2012 changes to AS/NZS4871 are more significant than generally appreciated. Traditional parameter values available under standards are not necessarily ‘safe’ when configured into a practical system.

Removal of prescriptive limits on key parameters including earth fault limits, trip settings and clearance times, requires all design settings to be examined from first principles.

Regardless of whether they fall below the wet area curve or not, all protection parameters should be justifiable as being as low as reasonably practical.

How to get there

  • Complete an audit of your system against the requirements of AS/NZS4871
  • Carefully consider the fundamental parameters including:
    • Earth fault limitation
    • Return earth impedance limit
    • Tripping ratio and total clearance times
  • Review underground substations for compliance against AS/NZS4871 and Safety Bulletin SB11-04 (variable speed drives and fitment of wideband earth leakage)

How Ampcontrol can help

Not sure where to start or need some help with an audit? Ampcontrol have a range of services available to help you.

Electrical engineering support: Ampcontrol’s electrical engineering team have the experience and expertise to understand and evaluate your electrical system. We can undertake protection and electrical distribution studies and provide electrical design advice.

Onsite support: Ampcontrol’s underground and HV service teams are available to conduct AS/NZS4871 audits. Our trained service technicians and electrical engineers audit your site, provide standardised documentation of audit findings, and provide recommendations for any issues identified.

Training: We provide practical training modules including how to set and configure electrical protection equipment as well as high voltage maintenance program requirements. Our training packages are custom designed to your site installation and include reference materials. Training can be conducted on a scheduled basis to ensure your staff remain up to date with requirements.


Hassle Free Shutdown Maintenance

It is proven that the more time and effort spent planning and preparing for shutdown the better the outcomes. Here is our simple guide to taking the guesswork out of mine shutdown management by looking at some of the common electrical issues faced along with some helpful tips to ensure you get back up and operational, on time and on schedule.

Download our guide to hassle free shutdown maintenance 

What Makes a Transformer Cost Effective?

Over the life of a transformer, the cost effective choice may not turn out to be the lowest first cost option.

In an environment of decreased capital spending, the economic benefits of purchasing a lower first cost standard transformer compared with a high efficiency unit are worth examining.

In producing a cost effective transformer for a client, transformer designers have an important role in finding the balance between delivering a low-loss transformer and controlling manufacturing costs.

Take a look at the design and manufacturing considerations, the full lifecycle costs and the economics of efficiency in this overview which you can download as a PDF of read below.

What makes a transformer cost effective?

The initial investment should not be the only consideration. A ‘total cost of ownership analysis’, whereby all associated costs and savings are examined, is an important step in the transformer procurement process.

Over the life of the transformer, the cost effective choice may not turn out to be the lowest first cost option.

Power utilities understand the importance of the total cost of ownership analysis and when procuring transformers through tender or quotation, they include a price capitalisation formula in their comparison of competitive bids.

However many industrial and mining customers, to their detriment, do not fully utilise this important costing method.

What is ‘total cost of ownership’?

As a transformer unit may be expected to operate for up to and often in excess of 30 years, economic variables such as energy losses and maintenance costs should also be considered in a total owned cost analysis, calculated over the life span of the transformer.

This method allows buyers to compare the total cost of ownership between low cost (low efficiency) and higher cost (high efficiency) transformers and make decisions based on informed fact.

Often the highest ongoing cost of operating a transformer is energy losses. Losses need to be converted to a present value to determine the financial penalty likely to be incurred over the planned life of the transformer.

Design and manufacturing considerations for efficiency and losses

Oil immersed and dry type power and distribution transformers are bound by energy efficiency standards (such as MEPS and HEPS in Australia) that specify the acceptable power loss levels of a transformer.

For utility companies, transformers can account for as much as 40% of network losses. This is essentially wasted electricity which over the life of the transformer can amount to huge financial losses.

There are two types of losses: load losses, which are proportional to demand on the network at any one time and no-load losses, caused by the magnetisation of the core steel, which are constant and independent of the electric current.

Manufacturing a low-loss, high efficiency custom transformer requires optimised design, manufacturing methods and materials.

In high efficiency transformers, iron loss is minimised by the use of low loss core steel built in the most efficient core configuration and low magnetic flux density. Load losses are minimised using high conductivity material at low current densities.

The most cost effective designs optimise the cost of material, the cost of power lost and the cost of finance over the transformers expected life time.

The performance gain may only be 1-2% improved load loss at 100% loading, yet the savings over the life of the transformer may be significant.

What makes a transformer cost effective

Transformer life cycle

The manufacturing cost is not the last cost of a transformer. A high efficiency model will reduce energy losses but will have other long term benefits, especially related to maintenance.

Efficient transformers run cooler, thus reducing the need for cooling mechanisms such as fans. The low temperature rise helps lessen stress on internal materials such as insulation and cellulose paper. With fewer fans requiring repairs or replacement, maintenance costs are minimised.

Environmentally, high efficiency transformers ultimately reduce consumption of fuel necessary to accommodate transformer losses.

The economics of efficiency

By putting capital and operating costs into a total cost of ownership formula, purchasers can derive and compare the real value of transformer options of different efficiency levels and purchase price.

The below example compares the total cost of ownership of a standard efficiency and high efficiency power transformer over 25 years.

What makes a transformer cost effective

 High efficiency transformer: the cost effective choice

The benefits are clear: purchasing a high efficiency transformer upfront will result in significant savings over the life of the transformer. Operators will also benefit from reduced maintenance costs as well as added environmental benefits.

For transformer manufacturers, the science is in providing the best value from the client’s perspective, balancing a cost effective build with ongoing operational efficiency.

*purchase price in this article is for purpose of this calculation only and is not indicative of an individual custom transformer build by Ampcontrol.

Find out more about Ampcontrol’s high efficiency transformers 


Ex Equipment Verses Ex Component

The differences between explosion protected (Ex) electrical equipment and Ex components. 

What are the guidelines/rules regarding the differences between flameproof ‘Ex equipment’ and ‘Ex component’, in regards to the use of empty flameproof Ex d enclosures by third parties to manufacture Ex equipment?

Download this content as a PDF or read below. 


It has been noted that certain service facilities have been purchasing empty flameproof enclosures, fitting and wiring the electrical equipment and supplying ‘new’ explosion protected equipment into the industry.

This practice is in breach of the IEC Ex standards and scheme. Whilst it might not be a safety issue, it is like driving a car on a public road without a license. It is not necessarily going to make the roads unsafe, but it is against the law and a criminal act attracting penalties.

The following scenario can be used to illustrate what is happening in the industry:

  1. Company ‘A’ is a manufacturer, has a QAR and is the holder of an IECEx equipment certificate for an Explosion protected product. (Flameproof Ex d).
  2. Company ‘B’ is a separate company registered as a service facility.
  3. Company ‘A’ manufactures an Ex d. enclosure and sells the empty enclosure to company ‘B’.
  4. Company ‘B’ installs the internal electrical components, completes the electrical wiring and conducts functional tests.
  5. When complete, company ‘B’ sells this Ex equipment to the end user using the original company ‘A’s certificate number and marking label.


Below are extracts from standards, Coal Mines Health and Safety Act and Gazette No. 10. Important parts to note from these references are highlighted for further consideration.


1. Scope

This part of IEC 60079 specifies the general requirements for construction, testing and marking of electrical equipment and Ex Components intended for use in explosive atmospheres.

3. Terms and definitions

For the purposes of this document, the following terms and definitions apply.

3.8.1 Ex Component Certificate – A certificate prepared for an Ex Component. See 3.28.

3.8.2 Equipment Certificate – A certificate prepared for equipment other than an Ex Component. Such equipment may include Ex Components, but additional evaluation is always required as part of their incorporation into equipment. See 3.7.4, 3.25, 3.27, 3.28, and 3.29.

3.28 Ex Component – Part of electrical equipment or a module, marked with the symbol “U”, which is not intended to be used alone and requires additional consideration when incorporated into electrical equipment or systems for use in explosive atmospheres.

28.2 Certificate – The manufacturer shall prepare, or have prepared, a certificate confirming that the equipment is in conformity with the requirements of this standard along with its other applicable parts and additional standards mentioned in Clause 1. The certificate can relate to Ex equipment or an Ex Component.

An Ex Component certificate (Identified by the symbol “U” suffix to the certificate number) is prepared for parts of equipment that are incomplete and require further evaluation prior to incorporation in Ex equipment. The Ex Component certificate may include a Schedule of Limitations detailing specific additional evaluation required as part of incorporation into Ex equipment. An Ex Component certificate shall clarify that it is not an Ex equipment certificate.


3.18 Ex component enclosure – Empty flameproof enclosure provided with an Ex component certificate, without the internal equipment being defined, so as to enable the empty enclosure to be made available for incorporation into an equipment certificate without the need for repetition of type testing.


(normative) NOTE: The terms ‘normative’ and ‘informative’ are used to define the application of an annex to which they apply. A normative annex is an integral part of a standard, whereas an informative annex is only for information and guidance.

Empty flameproof enclosures as Ex components

D.1 General – The purpose of an Ex component enclosure certificate for empty enclosures is to enable a manufacturer of flameproof enclosures to obtain a certificate without the internal equipment being defined, so as to enable the empty enclosure to be made available to third parties for incorporation into a full equipment certificate without the need for repetition of all the type tests. When a certificate concerning the full equipment is required, an Ex component enclosure certificate for the empty enclosure is not necessary.

D.2 Introductory remarks – The requirements for an Ex component enclosure certificate for an empty enclosure are contained in this annex. This does not eliminate the need for a subsequent equipment certificate, but it is intended to facilitate such a certificate.

The Ex component enclosure manufacturer shall be responsible for ensuring that each and every unit supplied

  • a. is identical in construction with the original design as detailed in the documents mentioned in the Ex component enclosure certificate,
  • b. has been subjected to such routine overpressure testing as is required, and
  • c. meets the requirements of the applicable schedule of limitations imposed by the Ex component enclosure certificate.

D.3.8 The Ex component enclosures shall be permanently marked internally according to the applicable requirements.

The marking shall be per 20.3(d), Table 10. The marking shall also include the requirements for marking of Ex components given in IEC 60079-0. This marking may be omitted if the Ex component enclosure manufacturer is also the holder of the equipment certificate.

D.4 Utilization of an Ex component enclosure certificate to prepare an equipment certificate

D.4.1 Procedure – Enclosures which have an Ex component enclosure certificate may be considered for incorporation in equipment certificates with IEC 60079-0 and this standard, normally without repetition of application of those requirements already applied to the Ex component enclosure, subject to compliance with the schedule of limitations detailed in D.3.10.

Documents shall be prepared for an equipment certificate depicting the specified equipment, any permitted substitutions or omissions, together with the mounting conditions within the Ex component enclosure, so that compliance can be verified with the schedule of limitations of the Ex component enclosure certificate.

Any hole permitted in accordance with the Ex component enclosure certificate may be provided either by the Ex component enclosure manufacturer, or through agreement between the equipment manufacturer and the Ex component enclosure manufacturer.


Part 2 Division 2 subdivision 2 clause 19 titled “Electrical engineering management plan” states;

(1) The electrical engineering management plan for a coal operation must make provision for the following:

(c) the use of electrical plant only of a Gazetted type in a hazardous zone,

New South Wales Government Gazette No. 10 titled ‘Types of Electrical Plant Used in Hazardous Zone’

In “Sub clause 1.4 Electrical apparatus:

  • for which a valid certificate of conformity exists, which accords with clause 2 of this Schedule, . . .

Clause 2. Valid certificate of conformity” Subclause 2.2 states “must be an AUS Ex certificate of conformity, or, an ANZEx certificate of conformity, or, an IECEx certificate of conformity, . .”

And lists the following definitions:

ANZ Ex certificate – A certificate of conformity issued under the Australian/New Zealand Certification Scheme for explosion protected electrical equipment

AUS Ex certificate – A certificate of conformity issued under the Australian Certification Scheme for explosion protected electrical equipment

IEC Ex certificate – A certificate of conformity issued under the International Electrotechnical Commission Certification Scheme for explosion protected electrical equipment

Note; all the above are ‘equipment’ certificates

And in Queensland, Coal Mining Safety and Health Regulation 2001, Chapter 4 Underground mines, Part 5 Electrical equipment and installations 182 ERZ1

1. The site senior executive must ensure fixed, mobile and transportable electrical equipment installed or operated in an ERZ1 at the mine is—
(a) suitable for use in an underground mine; and
(b) certified as having explosion protection.



A manufacturer is audited to ISO/ IEC80079-34 Application of quality systems for equipment manufacture and a Quality assessment report (QAR) is issued. SCOPE (extracted from the standard) This part of ISO/IEC 80079 specifies particular requirements and information for establishing and maintaining a quality system to manufacture Ex equipment including protective systems in accordance with the Ex certificate.


A service facility is audited to AS/NZS3800 Electrical equipment for explosive atmospheres— Repair and overhaul. SCOPE (extracted from the standard) This Standard—

(a) specifies requirements for and gives instructions, principally of a technical nature, on the repair, overhaul, reclamation and modification of equipment designed for use in explosive atmospheres;

(b) is not applicable to maintenance, other than when repair and overhaul cannot be disassociated from maintenance, neither does it give advice on cable entry systems which may require a renewal when the equipment is re-installed;

(c) prevents overhaul without manufacturer and certificate documentation to types of protection ‘i’ and ‘m’;


(d) assumes that good engineering practices are adopted throughout.

Note; the explosion protection techniques which have been assessed in the issuing of the RFS will be listed on the certificate and the RFS must operate within the defined endorsements.



To be listed as a manufacturer on a certificate, the manufacturer must have a QAR.

A list of manufactured Ex products are identified on or with the QAR.

Empty FLP enclosures when supplied to a third party shall have an ‘Ex component certificate’, not to be confused with an ‘Ex equipment certificate’.

If an empty enclosure with a component certificate is supplied to a third party, this does not eliminate the need for an equipment certificate to be obtained by the third party.


The scenario provided in the example at the beginning of this document is in breach of the IECEx rules due to the following;

  • As company ‘A’ sells an empty enclosure to company ‘B’, company ‘A’ is classed as a supplier and the empty enclosure is considered an Ex component.
  • Therefore, company ‘A’ is required to have an Ex component certificate (identified by the suffix ‘U’) for this enclosure as they are selling an empty enclosure.
    • The enclosure in question is not certified as an Ex component. 
  • Company ‘B’ is considered to be a manufacturer as it is manufacturing Ex equipment using an Ex component obtained from another manufacturer.
    • If an empty enclosure with an Ex component certificate is supplied to a third party, this does not eliminate the need for an Ex equipment certificate to be obtained by the third party.
  • As company ‘B’ is classed as a manufacturer of Ex equipment it must have its own QAR and be the holder of a Certificate of Conformity for the end product, now Ex equipment.
    • Company ‘B’ does not have a QAR.
    • Company ‘B’ does not own any Ex certificates for the product supplied.
    • Company ‘B’ is not listed as a manufacturer on the Ex certificate.
    • The end product is labelled with the original company ‘A’s Ex equipment certificate number.
      • This is in contradiction to the standards and the Ex certificate.
    • The new Ex equipment certificate as required above, will identify the empty enclosure as an Ex component by the Ex component certificate number.
      • There is no Ex component certificate from the original manufacturer and
      • There is no Ex equipment certificate for company ‘B’.
    • NOTE: Company ‘B’ is a service facility and not a manufacturing facility recognised by the IECEx scheme
  • As the above indicates the equipment does not have a valid AUSEx, ANZEx or IECEx certificate, therefore it is in breach of the Coal Mines Health and Safety Regulations both in NSW and Queensland.


What is a Neutral Earthing Resistor?

Earthing systems play an important role in an electrical network. For network operators and end users, avoiding damage to equipment, providing a safe operating environment for personnel and continuity of supply are major drivers behind implementing reliable fault mitigation schemes.

What is a Neutral Earthing Resistor (NER)?

A widely utilised approach to managing fault currents is the installation of neutral earthing resistors (NERs). NERs, sometimes called Neutral Grounding Resistors, are used in an AC distribution networks to limit transient overvoltages that flow through the neutral point of a transformer or generator to a safe value during a fault event.

Generally connected between ground and neutral of transformers, NERs reduce the fault currents to a maximum pre-determined value that avoids a network shutdown and damage to equipment, yet allows sufficient flow of fault current to activate protection devices to locate and clear the fault.

NERs must absorb and dissipate a huge amount of energy for the duration of the fault event without exceeding temperature limitations as defined in IEEE32 standards. Therefore the design and selection of an NER is highly important to ensure equipment and personnel safety as well as continuity of supply.

The Importance of Neutral Grounding

Fault current and transient over-voltage events can be costly in terms of network availability, equipment costs and compromised safety.

Interruption of electricity supply, considerable damage to equipment at the fault point, premature ageing of equipment at other points on the system and a heightened safety risk to personnel are all possible consequences of fault situations. By installing NERs on the distribution system and controlling fault currents and transient overvoltages, the following benefits can be realised: „

  • Elimination or reduction of physical damage to equipment „
  • Extended life of connected distribution equipment such as transformers „
  • Reduced operation and maintenance expenses „
  • Simplification and fast isolation and clearing of the original fault „
  • Improvement in network security and reduction in unplanned shutdowns

Find out more about the methods of neutral earthing and what to consider when specifying an NER in our quick guide to NERs.


What Does Power Factor Mean For My Business?

What solutions are readily available for business owners to improve energy savings and reduce electricity costs? Installation of Power Factor Correction equipment (PFC) is one answer.


Power factor is a ‘snapshot’ of how efficiently a consumer is using electrical power supplied from the network. In mathematical terms, it is the ratio of the active or usable power measured in kilowatts (kW), to the apparent or total power measured in kilovolt amperes (kVA), calculated as kW/ kVA = PF.

Apparent power (kVA) is the vector sum of the required active power (kW) and reactive power (kvar). While not performing any ‘useful’ work, reactive power is an essential and unavoidable element of electrical networks.

A consumer with a lower power factor than a neighbour of identical size will require additional kVA be supplied by the network. As such, additional power has to be generated and transmitted which has inherent incremental costs to the consumer and provider.

Power companies address the additional costs in a number of ways. Most commonly consumers are billed based on their kVA demand rather than kW demand to encourage more efficient use of energy, or in some cases consumers can face penalties for having poor factor.

Generally a consumer will have a connection agreement with an energy provider that dictates and defines requirements of power factor. Falling outside of these limits can result in penalties, imposed restrictions on expansion or in extreme cases disconnection. So it is generally in a consumer’s best interest to monitor and regulate power factor.


Power Factor Correction (PFC) is the process of reducing the kVA demand of a consumer by locally generating the site’s reactive power requirements. Local generation results in a reduction of reactive power drawn from the grid and hence a reduction in overall kVA consumed.

PFC is most commonly achieved by the installation of optimally sized capacitor banks that automatically switch in and out based on measured power requirements to achieve a target power factor (typically 0.95 or greater). By improving power factor, consumers are greatly improving the efficiency of their site and will potentially generate large reductions in energy costs.

 Benefits include:

  • Reduced PFC tariffs and penalties on your electricity bill
  • Increased available load/equipment capacity
  • Improved system efficiency
  • Improved quality of electrical supply
  • Reduced greenhouse emissions
  • Extended working life of plant machinery

Find out more about Ampcontrol PFC

The ROI of Power Factor Correction

Present issues surrounding escalating production costs, energy efficiency and a growing trend of electricity supply companies introducing kVA- based maximum demand charges are driving mining companies to re-think how they optimise their electricity supply and distribution infrastructure.

Often located at the end of the grid and characterised by heavy start up loads, mine sites are particularly susceptible to power quality issues. These issues can result in negative technical and financial impacts by interrupting production and driving up operational costs. It can also restrict plans for mine expansion.

Mines, considered very large energy users, are also being targeted by electricity supply companies to address their power quality (in particular power factor) to meet electricity supply standards and their electricity supply connection agreement conditions.

Power quality equipment and solutions are increasingly being considered to alleviate technical problems associated with poor power quality, reduce kVA demand charges and avoid capital outlay when looking to increase capacity.

This paper compares the ROI of installing new or upgrading existing equipment with the installation of Power Factor Correction to enable increased production at an underground coal mine. You can download the paper as a PDF or read more below.

What is power factor?

Power factor is a measure of how efficiently electrical power is being consumed on site. The way a business manages their power and electrical infrastructure is therefore incredibly important, as poor power factor can have a number of financial or operational implications.

While a power factor of 1 (or unity) is ideal, in most cases it is not economically viable as compensation is not a linear function. Though largely dependent on connection agreements, it is widely accepted that a power factor of 0.95 or higher is considered to be an efficient use of power, while power factor lower than 0.9 risks breaching agreements and can lead to higher than necessary kVA demands and subsequent higher electricity bill charges.

In the mining sector, power factor is affected particularly by the electric motors in longwalls, conveyors, ventilation fans, coal preparation plants etc., all of which use large amounts of energy and require large amounts of reactive power to support the network.

If a mine’s electrical system is not optimised for these types of loads, power factor is likely to be negatively affected. Poor power factor affects a mine’s operating efficiency and operating costs in several ways. Electrical losses and voltage instability in the system may be amplified, resulting in transformers or switchboards overheating, motor start issues and loss of torque at the cutting face. The consequence can be costly damage or a reduced life expectancy to electrical distribution and production equipment as well as possible loss of production through downtime.

A system with poor power factor draws more apparent power from the network and as a result the supply network needs to provide infrastructure and generation that will support this. To reduce the demands placed on the grid, end users are subjected to a demand charge (based on kVA) as an incentive to improve their power factor to reduce the apparent power the site draws from the network.

The application of power factor correction (PFC) systems compensate for some of the problems associated with the dynamic loads that are characteristic of mining networks. A PFC system will monitor and regulate a site’s power factor by energising optimally sized and designed capacitor steps that will locally supply the required reactive power to the connected loads, thus reducing the power drawn from the supply source.

Benefits of installing Power factor correction systems

There are a number of positive benefits associated with installing PFC equipment and solutions, as outlined below.

  • Tariff savings (avoiding penalties)

    Reduces costs where tariffs are related to KVA maximum demand, with poor power factor, you will pay more for your electricity supply as you are subject to KVA maximum demand charges. These charges can often be a large percentage of an electricity bill, with some as high as 25% of a total electricity bill.

  • Capital avoidance

    Reduce the loading of supply transformers, switchboards and cables and as a result release capacity in your electrical infrastructure and plant without expanding supply infrastructure, thereby avoiding or deferring capital outlay on upgrading or purchasing new equipment to increase your electrical capacity.

  • Mitigation of network and technical problems

    Provide voltage stability and as a result reduce or eliminate issues associated with voltage fluctuation that may cause difficulty with large motor start, low torque issues for cutting machines due to lower than desired voltage levels and starting fully loaded conveyor systems. In addition, a PFC system can be designed to filter harmful harmonic distortions which can cause premature failure of electrical equipment, nuisance tripping, breaching of connection agreements or impact the validity of Ex certifications of flameproof motors.


The following scenario is appropriate to mining operations that are considered very large energy users by their electricity supply network company.

An underground thermal coal mine in Queensland currently has a power factor of 0.8. The mine is a 66kV metered customer with billing partially calculated on kVA maximum demand and capacity charges with an Authorised Demand structure. The existing infrastructure features a 66kV /11kV transformer with 11kV switchyard, currently distributing to the underground mine as well as surface operations. One 11kV circuit
supports an 11KV/415V transformer with several ventilation fans. Another 11kV circuit supplies the underground, including continuous miners.

At present the mine is experiencing motor start issues with their ventilation fans and loaded conveyers.

The mine is planning on expanding their current operations to accommodate an additional continuous miner and increased production. To achieve this they have determined they will need to:

  • Install new, larger capacity cable for several kilometres underground to allow for an increased electrical demand
  • Upgrade the 66/11kV transformer
  • „Upgrade the existing 11kV/415V transformer (although this won’t fix the motor start issues)

The mine investigated two options to achieve increased energy supply and mitigate the operational problems.

Option A: Capital expenditure – installing new/ upgrading existing equipment

To cater for additional electrical capacity, the following installations/upgrades are required:

  • Increase transformer capacity at the 66/11kV transformer by installing cooling fans
  • „Replace the existing 11kV/415V transformer with one of larger capacity to support an additional vent fan
  • „Upgrade cable size underground to support the electrical load from an extra continuous miner

An initial estimate of these total upgrades would require over $600,000 in capital expenditure.

There are no electricity bill savings from this project/option.

It is noted that Option A does not mitigate the existing operational problems with starting certain motors and concerns about less than desirable torque for the cutters at the face.

Option B: Installing power factor correction

The installation of the following two PFC systems will yield the same increase (more in fact) in energy supply capacity as the installations/upgrades outlined in Option A, as well as mitigating the motor start issues currently being experienced.

  • „Install a low voltage PFC system on the 415V side of the transformer ventilation substation „„
  • Install a medium voltage (11KV) PFC system in the underground drift

An initial estimate of these systems would require $650,000 in capital expenditure.

This project will mitigate the mine’s motor start issues, as well as delivering a reduction in electricity Network Demand and Capacity charges of $180,000 per year based on the client’s existing tariff structure.

Business case comparison

The decision as to which project to proceed with is obvious by comparison:

Option A has a Capital cost of $600,000, but no reduction in Electricity Network charges.

Option B has a Capital cost of $650,000 and a reduction in Electricity Network Charges of $180,000 per year.

However, Option B is also delivering the capacity increase provided by Option A. A comparison of the two projects shows that the incremental capital for Option B is $50,000 more than for Option A. This means Option B’s incremental investment has a Return on Investment of 360% or 0.33 year simple payback as this option is also delivering a reduction in electricity charges of $180,000 per year.

Captech can provide assistance and advice on any aspect of power quality requirements, including power factor correction, kVA demand minimisation, voltage disturbance, harmonic filtering and voltage control analysis and solutions.

Find out more about our power quality solutions. 

Meeting Touch and Step Standards

Australian operators of power systems are required to meet Australian Standards concerning touch, step and transfer potentials.

Earthing systems form an integral part of any power system and provide personnel safety, equipment protection and system operating requirements for protection schemes.

The Standards
These standards include ENA EG1 and AS2067 which outline design and testing requirements. The 2010 version of AS2067 introduced the requirement to design and prove touch and step potentials to meet specific design criteria rather than simply ensuring that the grid impedance was below 1 ohm. Mining sites also need to meet the requirements of AS3007.2 for touch potentials and clearance times.

Why is it required?
New installations require injection testing to prove the Earth Grid design criteria has been meet. This injection testing results in touch potential measurements being taken and compared to the design criteria.

Periodic testing of Earthing Systems is also required as Earth Grid impedance can change due to corrosion of earth cables, changes in surrounding infrastructure, soil movement, excavation works and theft or vandalism. Periodic testing ensures the Earth System impedance has not changed from the commissioning stage thus ensuring the touch and step potentials are still within the design criteria.

How is it done?
Periodic testing on substation earthing systems is carried out to ensure compliance with the original design criteria or against the relevant standards when the design criteria is not available. This will ensure touch and step potentials remain at safe levels.

Our experience
We offer comprehensive field testing and analysis using state of the art off frequency current injection methods and analysis technology. Our services include measurement of soil resistivity, electrode and earth grid resistance, calculation of touch and step potentials, all completed without interruption as tests can be performed whilst the substation is still energised.

Our technology provides accurate knowledge of the voltage gradients around the earthing system allowing highly accurate analysis of the step and touch voltages that require monitoring. This is achieved using off frequency current injection in the area surrounding the substation. Our engineers can assess the stability of the measured voltages at increasing distances to provide an accurate earth grid impedance measurement.

Ampcontrol conducts periodic Earth Grid testing which includes the provision of manuals and documentation to support analysis and findings. These reports can be also supplied to relevant government authorities to support auditing processes.

We provide Earth System testing services for mining and industrial applications during commissioning of new substations along with routine Earth System testing for pre-existing systems. High Voltage safety compliance audits against AS2067 and AS3007 can also be conducted at the same time as the Earth System testing to confirm compliance to standards as well as the touch and step tolerances.