Are We Doing Enough Intervention?

North Sea oil and gas operators are failing to make the most from their existing well stocks, with some 30% (600) shut-in and 33 million barrels of oil equivalent (boe) lost due to well losses – the equivalent of a new west of Shetland field.

North Sea oil and gas operators are failing to make the most from their existing well stocks, with some 30% (600) shut-in and 33 million barrels of oil equivalent (boe) lost due to well losses – the equivalent of a new west of Shetland field.

The figures, from 2017 but reflective also of 2018, were presented by Margaret Copland, senior wells and technical manager at the Oil & Gas Authority (OGA) at this morning’s Offshore Well Intervention Europe (OWIE) conference in Aberdeen.

Restoring shut-in wells can add production at economic rates said Copland. According to the OGA’s data, 22 million boe of production was added in 2017, through intervention operations, at an average well restoration costs in 2017 averaged just US$6.4/boe. “That’s an amazing rate of return,” Copland told the event, which continues tomorrow. Yet, well intervention was carried out on just 14% of wells in 2017, she said. “We need to think about these wells in terms of economics. Given that 30% of wells are sitting shut-in – that’s not wells that are in cessation of production (COP), it’s 30% of the active well stock - there is something wrong with a 14% intervention rate. We should be at 30%, trying to get these shut-in wells online, assuming facilities can handle it (eg. water handling etc.).”

The biggest cause of shut-in wells is integrity issues, which drove 45% of intervention operations in 2017. The second biggest is water production, either being too much and choking off hydrocarbon production or there not being enough capacity to handle the water topside, said Copland.

Production losses, which amounted to 26 million boe in 2015, 37 million boe in 2016, and 33 million boe, hasn’t seen an obvious trend, said Copland. “33 million boe is the equivalent of a big field west of Shetland,” she said. “That’s the potential. These well losses are not an issue with compressors or pipelines, it’s issues with wells and we are not seeing this being addressed. We are not sure that the industry knows at a granular level what’s causing these losses. Some are obvious: wells falling over and nothing being done about it, but that’s not the majority of losses. We are often asking if they understand their well losses, are they doing failure mode analysis, what are they doing to prevent it happening and we are getting a lot of blank faces.”

A big concern is the lack of well surveillance. Operators appear to not be doing enough to learn about what is happening in their wells. The rate of well surveillance work was just 8% of the active well stock in 2017, despite a large prize that could be had by doing well intervention, Copland said. “I don’t know what that number should have been but 8% is too low. We need to increase surveillance. The amount of data gathering going on is abysmal. Many companies have performance standards for data gathering, but how many have met it? I think not many. Without surveillance data, without going in to get data, without using new technology like the logging on fibre line, we cannot make the business case to make these projects work.”

John Hand, Technology Program Manager, Conventional Assets, ConocoPhillips, agrees. Opening the second day of the OWIE conference this morning, he said that, for the US onshore conventional business, increasing production rates, “is a big data problem and all you have to do is get that data and get it in a form people can look at across disciplines. In the Eagle Ford (play), we used data analytics to cut the time to drill in half over four years.” At 22 days per well, drilling teams had said they were at their technical limit. That time was reduced to 12 days and then seven days, over a four year period, Hand said.

Shut-in wells that are not going to be brought back online should be abandoned instead of left until cessation of production for abandonment work, added Copland. “It would be more economic to do something to isolate the well and preliminary log well before that,” she said. “Maybe an operator will be short of trees, they could get a tree off one of these wells and get it turned around ready for the next time a tree falls over. Waiting until the end of field life doesn’t help anyone.”

The bigger picture is a UK North Sea that’s largely mature but still with remaining potential. Some 7500 wells have been drilled in the UK to date, with 44 billion barrels of oil produced. More wells are now being plugged and abandoned than drilled, and exploration drilling is at an all time low. But, production efficiency in existing fields has been improved, new seismic data is being shot, and “Elephant fields” could still be found west of Shetland, said Copland.

Improving well intervention and increasing production could help push back COP dates and extend the life of the UK Continental Shelf, she said. To aid that drive, Copland says the OGA is close to finalising a wells strategy which it will then use to question operators on their own activities to make sure they’re doing all they can. This strategy was due to be published by the end of Q1 2019.

Additional Info

  • Region: North Sea
  • Topic: Intervention
  • Month: April
  • Year: 2019
  • Content Type: Thought Leadership
Read 136 times Last modified on Thursday, 25 April 2019 00:08
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