Is there a cloud over NT’s energy transition?

At 2:18pm on Sunday 13 October last year Alice Springs suffered a System Black that impacted an estimated 12,000 customers for between 30 minutes and up to 10 hours on a “hot and humid” day[i]. Initial media reports focused on a passing cloud’s impact on solar generation[ii], which led to a sudden drop in output from the 4MW Uterne solar farm and rooftop PV.

But, as with South Australia’s system black in 2016 Alice Springs’s event was much more complex and more nuanced and stemmed from a set of cascading events.

In a report[iii] to the Northern Territory (NT) Government, the NT Utilities Commission commented that the Alice Springs system black could not be attributed to a single point of failure because there were multiple failures both in the events that led to the system black and then the subsequent restoration of the system.

One thing is clear (and again here there are parallels with SA experience) as systems move towards a higher level of intermittent renewable generation there is a need for much greater planning and co-ordination. The transition places greater reliance and importance on both demand and weather forecasting as well as operational planning.

The NT’s review of the Alice Springs system black indicate that the reliability issue could have been avoided or mitigated with better co-ordination and planning.  Overall, the review highlights the importance of having adequate supporting local generation or other matching technologies available at the times when they are needed.  All generation (renewable and thermal), as well as distribution technologies, can and will experience unexpected faults.  Of course, this is easy in hindsight but the assessment of the Alice Springs system failure does provide some valuable insights. So what went wrong in the NT?

Key issues

The Utilities Commission’s report found that key failures in the lead up to the system black included operating the system in an insecure state with insufficient spinning reserve and limited regulating reserve, as well as issues with the system’s automatic generator control (AGC), generator controls for the Jenbacher[iv] units at the Owen Springs Power Station (OSPS), a 5MW battery energy storage system (known as BESS) and the settings of the under frequency load shedding (UFLS) scheme.

Key failures in the restoration included a lack of or inadequate black start procedures, Jenbacher generator limitations and the delayed availability of the Ron Goodin Power Station’s (RGPS) major gas unit (R9) due to maintenance issues.

“Several failings in the restoration process were pivotal, and led to a significantly longer restoration process,” according to the Utilities Commission.

The Utilities Commission had power system consultants Entura provide a technical report on what occurred. That report highlights in detail the sequence of events, while also questioning the agility and robustness of the power grid.

Entura did not find that sudden cloud cover could be considered a root cause, noting that it is a credible event and power systems must be designed to be sufficiently robust to withstand all credible events.

Entura’s review observed:

• The initiating event for the system black was the sudden unforeseen “by those managing the system” reduction of solar output from the Uterne solar farm and from rooftop solar, which led to an increase in load on dispatched synchronous generation.
• If the automatic generator control (AGC), Jenbacher generators, battery energy storage system (BESS) and under frequency load shedding had functioned as expected then the initiating event would not have led to the system black.
• If two or more of the AGC, Jenbacher generators, BESS and UFLS had functioned as expected a system black was likely to have been avoided or limited to a technical black (where parts of the system remain energised), and that would have meant a reduced restoration period for customers.
• At the time of the incident Alice Springs’ system was not in a secure operating state because it had insufficient spinning reserve and “at best” zero regulating reserve.
• Confusion or lack of agreement on roles and responsibilities for the control and monitoring of the Alice Springs system under the Territory’s System Control Technical Code (SCTC) load following arrangements.

Background to Alice Springs’ power system

The Alice Springs power system has been undergoing a transition from the Ron Goodin Power Station, which is being decommissioned. The 44.1MW power station was commissioned in 1973 and has 8 reciprocating sets (2 diesel, 6 gas or diesel, and 1 turbine (gas or diesel).

The newer Owen Springs Power Station has1 gas and 3 MAN diesel engines to produce up to 36.6MW. An expansion of the plant involved the installation of 10 x 4.1MW GE Jenbacher high-efficiency gas-spark reciprocating engines. These are intended to replace the capacity of the RGPS, which is expected to close once OSPS is fully operational.

A 5MW battery (BESS) has been online since March 2019. It is capable of dispatching 5MW (around 10 per cent of Alice Springs maximum demand) for up to 40 minutes. It is also capable of flexing to 8MW for 6 seconds[v].

The 4.1MW Uterne solar farm was commissioned in July 2015 and Territory Generation has a Power Purchase Agreement with the operator Epuron for its output[vi]. Based on Clean Energy Regulator data, as at November 2019 there was 14.5MW of rooftop solar installed in Alice Springs (NT has a total of 95.6MW installed.), so Central Australia has a high solar uptake which, according to Territory Generation, “requires a very high amount of conventional spinning reserve to stabilise changes in the load pattern”[vii].

Detailed Events

At the time of the event the Ron Goodin Power Station was not in effective hot standby with no machines in service. A hot standby to cold standby[viii] transition was scheduled for 22 October subject to there being no forced outages on the Jenbacher units at the Owen Springs Power Station, but this was subsequently rescheduled.

It was also questionable, according to Entura’s assessment, that the power plant was in a cold standby state and the gas turbine generator (R9) was unavailable for service because it needed a two-hour repair.

There was process to prepare a black start procedure from OSPS using the Jenbacher machines, and Entura considered that the definition of hot standby[ix] should not have been relaxed or the maintenance/availability at the RGPS allowed to fall until this had been proven and finalised.

There were also concerns expressed about the automatic generator control system (AGC) – in particular Owen Springs MAN units (see description below) being regularly switched from AGC to manual control without an operator command and causing a deficit of regulating reserve.  

In the lead up to the system black Entura found that on the day the OSPS’s MAN machine – there are three 10.8MW high-efficiency MAN 51/60DF dual-fuel generator sets and one was out of service at the time – was set for AGC control and a maximum output of 8MW (compared to the rating of 10.8MW). About 7 hours prior to the system black unit 1 came out of AGC control, with a possible cause being the transition between fuel types. The machine was returned to AGC control 10-15 minutes later by operator intervention. About 4 hours before the system black unit 1 came out of AGC control again and this was not detected by operators at System control or the Remote Operating Centre at Berrimah.

The output of the Uterne solar farm was relatively constant at around 3.3MW until 1:43pm, which is when a cloud passed over the station and the station’s output became variable with output dropping to as low as 0.5MW.

The technical report found that about 30 minutes before the event:

• OSPS unit 1 was online but was in manual/droop control. The plant’s Jenbacher units 5, 8, 10, 12 and 13 were online and operating near capacity and in AGC control. Its Jenbacher unit 9 was in the final stages of loading after being started to maintain system spinning reserve.
• The Uterne solar farm was generating at about 3.6MW, close to its maximum (4MW).
• The BESS was in service and ready to provide power if required.
• RGPS was shutdown and had several machines ready for service, although the major gas turbine (R9) was not available.

Entura found that the battery system responded “aggressively” to the trip of OSPS unit 8 by injecting around 2MW into the network to support frequency. When the OSPS unit 9 tripped the BESS output increased to around 6MW or 75 per cent of the total lost generation.

Subsequently, when the third Jenbacher machine tripped the BESS was commanded to 8MW. The total MVA (Megavolt-amperes) of the BESS exceeded its short time capability and an internal protection element tripped it from service.

Entura noted that the aggressive intervention of the BESS and the Jenbacher units may have been counterproductive because it meant the UFLS scheme was unable to detect that the power system was under severe stress. Had the frequency been allowed to fall the UFLS would have removed load from the power system and system black would have been avoided.

Official response

The Utlities Commission has endorsed the 15 recommendations made by Entura to address the issues identified. A full list of the recommendations can be found here (see pages 20-24).

The NT Government responded quickly by setting up the reviews of the system. Given its commitment to 50 per cent renewable energy in the mix by 2030 and the challenges this poses for the existing system, there is political risk attached to not getting it right.

The expected increase in the uptake in rooftop and large-scale solar which has been enabled by local and nationally supportive policies requires the support of ancillary services to ensure reliability and stability of this system. It also means predicting demand on traditional generation and forecasting weather becomes more challenging.

Following receipt of the Utilities Commission’s work and the Entura it announced that it had accepted 14 recommendations, while it accepted one in-principle (recommendation 6 relating to operating protocols), while it sought further information from Power and Water and Territory Generation[x].

Apart from the recommendations, the independent investigation recommended that until all of its high priority recommendations were implemented, the Ron Goodin Power Station should be maintained in a state that it could black start the entire system and the Government has also accepted this.

The Minister for Renewables, Energy and Essential Services, Dale Wakefield, said that the clear message from the independent investigation “is that there was an unacceptably low level of preparedness by the Power and Water Corporation and Territory Generation.

“Following receipt of the final independent investigation on 2 December, the Chairs of both the Territory Generation and Power and Water Corporation boards were informed that the Government no longer had confidence in the CEOs of the two corporations.”

The NT Government has committed to open and transparent progress reporting on the implementation of the recommendations and has asked the Utilities Commission to publish these reports.

Finally, the Utilities Commission advised a "measured approach" should be taken to achieving the Territories’ 50 per cent renewables target to allow for the transition to be co-ordinated and managed, while minimising costs and maintaining reliable supply.

In its response[xi] the NT Government said its “guiding principles are that the 50 per cent renewable energy target by 2030 is achieved while maintaining the delivery of reliable and secure electricity at least cost to consumers and taxpayers. The Government will continue to carefully manage the implementation of renewable energy consistent with the observations of the Utilities Commission report.”

If the NT report tells us anything it is that the ability of the system to respond quickly and adequately particularly during the transition to a new grid prevents or mitigates the reliability impacts of such events. It also underscores the need for careful planning, forecasting and effective operational procedures

[i] “No power for eight hours on hot, humid day”, Alice Springs News 14 October 2019

[ii] “Shine comes off solar from Alice Springs failure”, Katharine Times, 10 December 2019

[iii]

Independent Investigation of Alice Springs System Black Incident on 13 October 2019, Report to the Minister in accordance with section 6 (1)(g) of the Utilities Act 2000, 22 November 2020 (Updated 2 December 2020).

[iv] The 77MW Owen Springs Power Station was upgraded with 10, 4.1MW GE Jenbacher high-efficiency gas-spark reciprocating engines. Its existing units were 3 reciprocating engine units x 10.9MW and 1 gas unit x 3.9 MW.

[v] Territory Generation Annual Report 2018-19

[vi] Ibid.

[vii] Ibid.

[viii] Cold standby is defined as no Ron Goodwin machines in service but all sets that are operational at the commencement of cold standby to be maintained in a state of readiness that they could be started at any time.

[ix] Hot standby – includes at least one Ron Goodin machine being in service and operating and operating at minimum load.

[x] http://newsroom.nt.gov.au/mediaRelease/31829

[xi] Northern Territory Government Response to the Independent Investigation of the Alice Springs System Black Incident on 13 October 2019, 9 December 2019