Over the last 15 years in particular, several offshore Western Australian & Timor Sea crude oil producing facilities have been decommissioned and abandoned, or shut in with the intent of abandonment. Some of the fields associated with these shut in facilities are represented in the table below.

Were these fields shut in prematurely, or could they have produced for longer under the right circumstances?

From an Acquisitions & Divestitures standpoint, would a transaction and transition of ownership have extended the life of any of these oil assets? Notwithstanding that in some historical cases attempts to transact were actually made. How can we further facilitate the purchase and sale of oil producing assets?

This article has been posted to generate discussion rather than to be comprehensive. Opinions and direct experiences of the oil assets mentioned would be welcome.



First Oil

Shut in

Production rate at date of shut in






July 1989

Aug 1992






Oct 2009




Laminaria / Corallina

Nov 1999

June 2019





Dec 1999

Nov 2004





June 2003

May 2012




Mutineer / Exeter / Fletcher / Finucane


July 2018





Sept 2007

Mid 2009





Oct 2011

June 2015





Aug 2014

March 2016



In a probable over-simplification, this is a profitability question, as to whether oil can be extracted and sold for more than the associated expenditure. Were economically producible hydrocarbon volumes left behind? Several of the oilfields in the above table were shut in when producing +4000 boe/d (US$75M to US$150M in annual revenue assuming $50-100/barrel), suggesting that with the right approach, they could have continued to produce profitably.

Neither the revenue side nor the expenditure side of the profitability equation are fixed, or out-with the control of asset owners.


A maximised production rate is a key factor on the revenue side of the equation. Production efficiency will be influenced by the following, to name a few, several which also appear on the expenditure side of the equation:

  • age and condition of facilities;
  • the sustaining capex and opex philosophy;
  • safety performance;
  • operational contractual model and performance;
  • engagement and relations with the relevant regulators;
  • operational system redundancy; and
  • reservoir performance to name a few.

Oil price and the timing within the commodity cycle is going to be very important to field life longevity and is of course out-with the control of asset owners. The date of each field shut-in is shown graphically on the oil price graph below.

Although some production has been shut in for abandonment during periods of lower oil price, that has not always been the case. So, there must be more relevant influencing factors – what else is important? Offshore assets such as these are complex and cannot be shut down nor restarted at a moment’s notice, which means there can be a lag between an abandonment decision and the actual moment of production cessation of many months.

An oil price hedging strategy could also be utilised to de-risk revenue projections and potentially extend field life.

First Oil and Field Abandonment Dates plotted against Nominal Oil Price
First and Last Oil of Fields plotted against Nominal Oil Price


Which of the above-mentioned factors, or others you know of, were influential in the cessation of production of these fields?

1. Talisman: Was it primarily a victim of low commodity price at the time (1992), and that the Amulet discovery wasn’t made until 2006, too late to be tied in and reduce the overall cost per barrel?

2. Griffin: What components of opex or production uptime made 4000 bopd non-economic?

3. Laminaria / Corallina: The FPSO and reservoirs were sold to Northern Oil and Gas (NOGA) in 2016. This opex model is quite different to the other examples in that this is an owned FPSO, as opposed to leased. NOGA went into Voluntary Administration in September 2019 and Liquidation on 7 February 2020. Could or should this have been a different result for NOGA?

4. Buffalo: If FWI could have been applied in in 2004, would there have been infill drilling rather than abandonment?

5. Wollybutt: The southern lobe was developed and extended field life. Could the field life have been extended further?

6. Mutineer Exeter Fletcher Finucane: To what extent was the high cost of subsea ESP workovers a factor? i.e. it is expensive to reinstate production revenue. Nevertheless, MEFF had dual ESPs and some identified infill drilling locations that were never drilled.

7. Puffin: In 2008 AED sold 60% of Puffin to Sinopec for US$561million, and by August 2011 AED was in administration. It is understood that reservoir performance was a major issue, only 2 mmbbls produced instead of the expected 100 mmbbls, but to what extent were other factors important? Was subsea well integrity an issue?

8. Kitan: Hibiscus petroleum proposed to buy Talisman’s 25% Kitan interest in June 2014 for $18m, but that deal fell through in June 2015. In the same month, attempts for FPSO dayrate renegotiations fell through and the field was promptly shut in. Could or should these ideas have extended the life of Kitan?

9. Balnaves: Was this shut-in just collateral damage in the Apache multi-billion dollar asset sale to Woodside?


Some components on the expenditure side of the equation vary significantly from operator to operator as demonstrated by the large reductions in operating expenditure achieved by smaller next-generation companies taking over older assets. Examples of successful asset transitions to leaner, nimble operators include Stag and Montara recently to Jadestone, and Wandoo to Vermillion back in 2005. What factors have made these deals successful? Timing in the commodity cycle, price, production, reserves, facility ownership, opex? The fact that Wandoo was producing around 8000 bopd when purchased by Vermilion must have been an important factor. It is also noted that the 9 examples featured in this article were all FPSO developments, whereas Stag and Wandoo are both FSO developments.

It is noted here that others have succeeded for a short while before failing, notably NOGA (Laminaria / Corallina) and Tamarind (Tui in New Zealand) both entering into administration in 2019.

If the current asset holders are no longer the natural owners, how do we help facilitate the transfer of ownership? There is plenty of literature on best-owner lifecycle, and it applies as much to oil and gas operations as other industries. The addition or reinstatement of production via workovers and infill drilling requires allocation of capital that may no longer suit the current asset holder but may suit a new owner.

Of course, this discussion would not be complete without mentioning the abandonment and decommissioning elephant in the room, where it is financially advantageous to delay decommissioning expenditure for as long as the assets retain integrity. It will be interesting to see how decommissioning is ultimately handled for the Laminaria/Corallina fields. At this point I suggest clicking through to my 2018 commentary article on how the UK North Sea has been addressing this matter of decommissioning liability for many years via innovative approaches.

Other than transacting late-life assets to smaller next generation operators, what else is important to extend the lives of these fields?

Is it via technology such as seismic FWI used at Buffalo – if this had been available and employed in 2004, could Buffalo have been extended? Or is it via the use of artificial lift such as ESPs at Stag and the conversion of wells at Wandoo from gas lift to ESP.


Were these fields shut in prematurely, or could they have produced for longer under the right circumstances? Do you have any particular thoughts and experience related to the oil assets mentioned?


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