Pain in the Annulus

Elaine Maslin

January 1, 2016

Well plugging and abandonment activity as part of offshore decommissioning is starting to ramp up – but could it be done better? Elaine Maslin reports.

Interwell’s exothermic P&A solution.  Image from Interwell. 

Decommissioning is a place no operator wants to go, but, it has the potential to be big business and it’s a task one no one can afford to ignore.

In 2014, globally, there were some 12,000 facilities, including floating facilities, platforms and subsea structures, according to Brian Twomey, managing director, Reverse Engineering Services, all of which will eventually need decommissioning.

But, the main cost in decommissioning is the well plugging and abandonment (P&A). According to 2015 estimates by industry body Oil & Gas UK, well P&A accounts for 46%, or nearly half the cost of decommissioning. That’s 3% higher than the last estimate, made in 2014, by the same body in its annual Decommissioning Insight report.

Over 1224 wells are due to be P&A’d alone in the UK North Sea over the next decade, at a cost of about US$11.5 billion (£7.7 billion), representing 30% of the 4300 wells on the UK Continental Shelf (UKCS). This is also an increase on the previous years’ estimate, which was some 930 wells over the next 10 years at a cost of $9.6 billion (£6.4 billion).

The scale of the task is just as daunting on the Norwegian Continental Shelf, which will have an estimated 7000 wells that will have been or need to be P&A’d by 2050, according to a 2014 report by the University of Stavanger. Wells take 21-125 days to P&A. Using 10 rigs, with zero downtime, it could take more than 57 years to perform P&A on all these wells, the report points out.

A global challenge

Per Jahre-Nilsen. Photo from DNV GL.

Globally, there is also a huge offshore well stock and it’s increasing, including deepwater wells, which will attract even greater costs. To date, there are about 1400 deepwater wells, Twomey said, speaking at the Oil & Gas UK and Decom Offshore’s Offshore Decommissioning conference in St Andrews, Scotland, late 2015. One deepwater well recently abandoned offshore Brazil cost a “number which will dwarf any of your [North Sea] wells,” he says. “Just in Brazil alone, the well P&A is enormous,” he adds. “The same situation is developing in Angola and West Africa. We are doing a lot of work in South Africa and they got a real shock how expensive it is to do well P&A.”

The issues are legion in P&A. On the Ivanhoe and Rob Roy field decommissioning project, Hess spent between 17 and 117 days per well on P&A, the Offshore Decommissioning conference heard, highlighting the range in scope on different wells.

“In some parts of the world you’re dealing with hazardous materials such as mercury,” Twomey told the conference. “This is a problem no one really knows a solution to. If you get organic mercury it’s almost impossible to get it out. You can’t just fill it with concrete and it will seep out. There are many issues like this emerging.” So, is the industry going about how it P&A’s wells the right way? It wouldn’t seem so. Some of the issues are organizational.

ConocoPhillips and BG Group outlined to the Offshore Decommissioning conference how they have been working on new organizational structures for decommissioning. Shell has learned the hard way on its massive Brent decommissioning project, which started in 2006, with P&A work beginning in 2008.

“Key lessons are making sure you have the correct organization that’s fit for purpose,” Duncan Manning, Brent Decommissioning Project manager, told the conference. He also cited transition planning, looking at batch operations and, what might seem obvious, making sure the rig is ready for P&A operations and what alternatives there might be. “Starting a P&A campaign without knowing what is in those wells is something we will not be doing again,” he added.

Risk-based P&A

Statoil’s Huldra platform, which has been used to help verify DNV GL’s P&A guidelines, and resulted in 30-40% well P&A cost savings. Photo from Statoil/Kjetil Alsvik. 

But, significant savings could be made by taking a risk-based approach to P&A design, says Per Jahre-Nilsen, business development leader, Drilling & Well, DNV GL. At the moment, the industry takes a prescriptive approach, using the same method to P&A wells, from high-pressure wells to dry holes, as set out by industry standards, i.e. Norsok and others, he says. Yet, the regulations in Norway and the UK set out a risk-based approach.

There is also very little consistency from basin to basin on standards. In Norway, the UK, and the US, the standards set out having two plugs, across 100m, 30m and 30m, respectively, he points out. In the Netherlands and Germany it is one plug across 100m. Australia and Malaysia say one plug across 30m. What’s more, Jahre-Nilsen says, well P&A concepts date back to early onshore practices, which were adapted for the offshore in the 1970s and have change very little since.

“When these methods were developed we had little understanding of marine life, ocean currents etc.,” he told an Intsok/Scotland Development International event in Aberdeen late November. “With our increased knowledge and understanding [on a site specific basis] we can probably reduce the number of plugs and the overall length and use different materials because we can say something about the probability of that well leaking and what the impact might be. This means that hazardous wells will get the attention they deserve and benign wells will avoid excessive rig-time and expenditure.”

DNV GL has been working with Statoil for two years developing the new approach and trialing it on the Huldra well P&A program, offshore Norway, as a form of verification, with positive results. It has saved 30-40% costs, Jahre-Nilsen says, reducing the number of well barriers. The guidelines were officially launched in November.

Norway’s Sintef, a research organization, is also looking into P&A challenges. Dr. Malin Torsæter, a research scientist from Sintef discovered there was a lack of well plugging data, or efforts towards P&A technology research and development in 2013. But, she says, there is also a significant potential market here for those willing to create new technologies.

“The global potential means there is a huge opportunity for this business,” she told the Intsok/Scottish Development International event, hosted at Aker Solutions offices in Aberdeen. Torsæter agrees that taking a prescriptive approach to well P&A is wasteful and also says that new technologies are needed. Work needs to be done to find technical solutions to today’s problems, such as finding logging tools which can see through steel pipes to assess integrity in order to be able to place a plug, she says.

“80% of P&A time is spent on cement and steel removal, because the integrity of that cement and steel cannot be assessed,” Torsæter says. Pulling pipe out of wells also needs to be simplified, she says.

Others agree it is time to do things differently. A joint report by Oil & Gas UK and Decom North Sea, Adoption of Novel Solutions Report 2015, says, in well P&A, intervention in the wells typically uses the same tools used when the wells were drilled and that P&A campaigns would reduce costs.

Sintef is looking at different cements, which would be able to work with the tubing left in the hole, and developing multi-tasking tools to reduce the number of trips down hole, as well as long-term monitoring at the sand face. The latter is being tested as part of a long-term pressure test using CO2 in Germany, which aims to test, or prove, current standards.

Jahre-Nilsen says other materials to cement are also being looked at, such as epoxy. Interwell has been working on a solution which would melt the materials in the well to create a plug using an exothermic reaction, Jahre-Nilsen points out. This would be a quantum leap, he says. Interwell is working the technology towards qualification with an objective to release it to the market by 2H 2016.

Sintef is also creating a wells data base, in order to help the Norwegian put a “price tag” on the task, which, ultimately, tax payers have to pay a significant proportion (78%) of, as in the UK (50-75% in tax relief), making P&A costs a matter of public interest. Sintef also has a project looking at “Shale as a barrier,” which is considering if shales etc., could close the hole themselves and if so how tight would the hole be.

Sharing experiences is also key, according to the Adoption of Novel Solutions report, especially where operators have been able to use a sustained campaign approach to reduce costs. Yet, as Torsæter found in 2013, information isn’t that easy to come by. A P&A campaign which involved a number of the operators on the UKCS was transformed thanks to one operator sharing their previous P&A well data. Yet, despite the acknowledgement of how useful this information sharing was, neither the campaign nor the operator was named at either event this was mentioned at.

There is no time to lose, however, as activity in this area is ramping on the UKCS. The number of wells P&A’d on the UKCS has tripled over the last five years and there are due to be some 900 wells P&A’d up to 2023, according to Colette Cohen, Senior VP Centrica Upstream UK and Netherlands, speaking at the Offshore Decommissioning conference, citing figures from UK-based consultants McKinsey & Co.

It would also seem like an opportune time, with rig rates low as units sit idle. Yet, the Norwegian Petroleum Directorate has warned against a suggestion made in the basin to plug wells to keep rigs busy, requesting that thought is given to reuse first. Nothing is ever simple.