While Australian contractors may be waiting a while yet, lessons can be learned from the UK where the situation is very different.
Industry body Oil & Gas UK said decommissioning in the North Sea was forecast to cost £50 billion ($A97.7 billion), with a £1.5 billion spend in 2016, according to its North Sea Activity Report 2016.
In 2015, 21 fields stopped producing, and 80 more are expected in the next five years.
The scale of the task for the UK industry was presented at Curtin University last month by Dr Dominic Ahiaga-Dagbui, project management lecturer at Robert Gordon University, Aberdeen.
Ahiaga-Dagbui said that, along with technical challenges, the industry must navigate complicated approval processes, agree on the assignment of liabilities and manage complex stakeholder issues.
The industry does have some clarity however on the scope of the decommissioning required and the liabilities of title holders.
In the UK, removal of all installations is the base case requirement, Ahiaga-Dagbui said.
Exceptions apply to less than 10% of installations, mainly concrete gravity structures, steel piled jackets weighing more than 10,000 tonnes and installations where removal would be too risky.
Steel installations installed after 1999, when the current rules began, are not exempt and must be removed.
The UK also imposes a more complex structure for liability for decommissioning costs.
Not only are title holders liable if their co-venturers cannot pay for decommissioning, but also previous title holders are liable if the parties they sold the asset to cannot meet decommissioning costs.
Australia is not facing the same scale of decommissioning as the North Sea, nor is it as immediate.
However, it is now over 50 years since Australia's first offshore well was drilled in the Bass Strait, discovering the Barracouta gas field. Eventually, large-scale offshore decommissioning will be required in Australia.
Australian regulatory mechanisms to facilitate this decommissioning work are less prescriptive than in the UK.
While complete removal is provided for, partial removal is also allowed and in these circumstances there is a residual liability risk to be dealt with.
Navigational risks will not be one of those liabilities, according to Stuart Barrymore, a partner at Herbert Smith Freehills, as international treaties require a clear water column of at least 55m below sea level.
For other residual liabilities from partial abandonment, however, Barrymore said that "if the title is surrendered and everything has been restored to a standard acceptable to the regulator then the liability for any subsequent risks associated with what remains passes back to government".
Nor, according to Barrymore, does Australia in most scenarios have North Sea style liability passing back to previous title holders.
The government may direct the last title holder to carry out remedial work in situations where the title has expired or been terminated, he said. However, when a party has transferred its title to another, that party has no ongoing liability to the state.
This leaves the question of who pays for a decommissioning project if the titleholders, for whatever reason, are not able to do so?
Barrymore, in a paper presented to the Australian Mining and Petroleum Law Association last year, makes clear that the government will assume this responsibility.
The paper contrasts the effort that title holders go to in their joint operating agreements to protect their interests concerning decommissioning costs with the absence of any security provisions within the regulations to protect the government.
The Australian government, in response to the Montara oil spill, now requires title holders to demonstrate to NOPSEMA their capacity to cover the costs of an oil spill.
In his paper, Barrymore notes one option that the government could investigate is applying this concept of financial assurance to decommissioning costs. However, he cautions this would be very complex and that an obligation to provide security will tie up productive capital.
Title holders also receive no explicit guidance from the regulations on when decommissioning should occur and what it comprises.
The current process, as described in Barrymore's paper, involves consultation with numerous authorities. While this provides flexibility, it is not certain, and there is no easy recourse for title holders if they are dissatisfied with the decision as to how their facility is to be decommissioned.
The Australian government has a lot at stake in how decommissioning works. As well as balancing environmental protection and encouraging investment and production, it is also effectively exposed to up to 58% of the costs under the tax system.
The exposure exists as decommissioning costs are normally income tax deductible, and can also give rise to a refundable credit under PRRT. This credit can offset PRRT liabilities or other taxes. The maximum credit is the total PRRT paid by the title holder on that project.
In some cases, the PRRT credit could result in a cash payout from the government to the title holder, according to Tristan Boyd, a senior associate at Greenwoods & Herbert Smith Freehills.
Canberra is considering its management of various aspects of offshore petroleum regulation. The Department of Industry, Innovation and Science in an interim report in November 2105 identified the development of a clear framework for managing decommissioning as one of four areas for action.
However, decommissioning was the lowest priority of the four.
"It has been a live issue within government for some ten years, and however the issues associated with the response to the Montara spill have quite understandably taken priority," said Herbert Smith Freehills' Barrymore.
Given the complexity, it is easy to understand why Canberra may want to put off dealing with commissioning.
However, the current situation is problematic for both the industry and government.
In Australia, unlike the North Sea, decommissioning requirements cannot be included in a design basis as there are almost no clear scope requirements.
A question mark hanging over the timing of decommissioning also makes late field life investment more difficult.
Selling an interest in a project late in its life is complicated as the new owner's PRRT credit for decommissioning costs will be capped by the PRRT it has paid, which will be less than other joint venturers who have been in the project from the beginning.
The joint venturers will then have very different economics when they consider decommissioning, complicating the decision.
For Canberra, there are negligible incentives for the industry to do anything else but continually put off decommissioning expenditure.
The North Sea Activity Report 2016 notes that some companies may prefer to operate at a loss rather than incur large decommissioning costs, given current capital constraints. Moreover, when oil prices are high and money is available, the argument will be that costs are too high.