Elaine Maslin surveys some of the plugging and abandonment solutions presented at Sintef’s Experimental P&A Research for the North Sea event in Trondheim, Norway.
Alexandra Bech Gjørv
Plugging and abandonment (P&A) work is not drilling. It sounds obvious, but it’s perhaps a phrase needed to help drive new solutions in the P&A space, a challenge that Norway’s research institute Sintef has set itself. Private equity cash in Norway is also setting its sight on this space, because it is hugely costly area, and one in which a new technology could save operators time and money, with the potential to have a global impact – and not just in oil and gas wells, as geothermal and CO2 storage wells will be seeking similar solutions.
Norwegian private equity house ProVenture, which invests in early stage start-ups, is one of those diving into the P&A technology space.
“P&A is a huge cost for operators,” said David Lysne, ProVenture’s senior partner, addressing Sintef’s Experimental P&A Research for the North Sea event in Trondheim, Norway, in late March. “The numbers are so big, it is a huge market and of a lot of interest to us and others.”
A Norwegian, but also global challenge
Alexandra Bech Gjørv, president and CEO at Sintef, told the Trondheim event that there are 4200 wells on the Norwegian Continental Shelf. Of those, only 250 have been plugged and abandoned, and a further 1650 have been partially abandoned.
“In the UK, there are 5000 wells. Globally, millions of wells need to be plugged.” There’s a large opportunity for those wanting to tackle this issue, and not just in the oil and gas industry, she says.
The chief aim is to reduce costs, mostly via reducing rig time. “Some new innovations have been introduced, but targeted research and development are needed for a step-change. Well plugging isn’t reverse drilling,” Gjørv says.
But, when it comes to investing in P&A technology firms, “there is a dilemma,” Lysne says. “If one [technology] succeeds, many others will not and they will take over a lot of the market.”
One company with such potential, he says, is Interwell, which has been testing a thermite plug technology. The plug uses a thermite reaction to effectively burn through the well and into the formation creating a seal without having to remove casing, etc. “If that’s excepted by the operators, that will wipe out the need for a lot of other technologies,” Lysne adds. “That is one of the dilemmas we face [as an investor].”
Government regulations in P&A are also a little bit vague, creating uncertainty, he says. “We have NORSOK guidelines, but they are just guidelines. Interwell goes beyond the Norwegian standards. We also know others that do the same, go beyond the Norwegian standards.”
There’s also the problem of when the work will come. “We are all waiting for the Tsunami of P&A wells we have been hearing about over the years,” Lysne says. “We want to know when it is coming. Maybe it’s building up and becoming bigger than we think.”
Reducing rig days, the Statoil way
Statoil’s Huldra platform. Image from Statoil/Kjetil Alsvik.
Statoil will have limited P&A activity until 2020, because it is focusing on keeping production rates up, says Pål Hemmingsen, project leader P&A technology strategy, Statoil. Statoil will start major campaigns on platforms in 2020, and then subsea wells from 2025, he says, adding that these dates could change as life time expectations of fields and oil prices change. The work the Norwegian major has been doing, however, has seen it reduce rig time on P&A work considerably. Hemmingsen says that Statoil has reduced P&A per well time by 47%. Last year, Statoil P&A’d 18 wells (nine on Volve, six on Huldra and six single P&A jobs), taking an average 17.8 days compared to 33 in 2014.
The reduction stems from an improvement plan set out in 2014. This plan focused on three steps: performing best practices and improving planning; incremental technologies; and then game changing “radical” technologies. These are technologies that can be run using well intervention methodologies, or on a platform when the rig is being used for other purposes.
The 47% reduction in 2014-2016 was achieved largely through improved planning and focus on costs, Hemmingsen says, as well as simplifying P&A design – making it “fit-for-purpose.” Rig time was reduced by using production tubing as a cement stinger by cutting it and lifting it to the desired area.
“When we started investigating, we found that, in most cases, barriers are good, and we don’t need to do section milling. In many cases, the formation has crept in to the casing, and can be used as an element in the well barrier,” he says.
To use the in-place cement as a barrier, it needs to be verified, which poses a difficulty. At the moment, pipe or tubulars between the outer casing and cement must be removed.
“You have to have efficient placing of the plug, but you need to be able to verify it too,” Hemmingsen says. “Using different barriers will also require qualification, unlike current cement when used to agreed lengths. But altering the length [of cement used] or using a different material would need verification.”
Projected Norwegian P&A activity. Source: Oil & Gas UK.
Statoil has been assessing its well stock – 1200 to date – and is categorizing them on how easy it would be to do intervention-based P&A, including using wireline or coiled tubing. Almost half of platform wells were in this category. Subsea wells were more complex, however, with multiple tubulars and smart wells with control lines. “There is a huge range of well designs and we will need different types of technology to P&A these wells,” Hemmingsen says.
Statoil is looking at various concepts, including using explosives to create a radial cut around one or more casing sections, and using a thermite plug, such as Interwell’s concept. But, to use such technologies, questions around how to place barriers and how to verify them still need to be answered. Hemmingsen says that it is believed cement barriers could also be shorter, but that issues around placement and verification remain.
Formation as a barrier
Verification is also something of a challenge for another technique in the P&A space – formation as a barrier. This is where the surrounding formation exerts pressure on the well such that it creates a natural seal. Truls Carlsen, advisor for wellbore stability and drilling practice, Statoil, says the Norwegian major has been looking at this for over 12 years, mostly in the southern [Norwegian] North Sea and Norwegian Sea.
Carlsen says that there’s a wide range of lithologies in which this sort of “creep” can happen. Statoil first saw it at the Oseberg field, where it got a signal from a cement bond log, where there wasn’t supposed to be cement. These were in clay ridge intervals, Carlsen says. It was cut and pressure tested to check there was no leakage across the section. It can take just two days, from drilling a well, running casing, and cementing, especially in green clay, he says.
After the results on Troll, over three years, more than 300 wells have been tested for formation bonding and the technique has been used on 25 fields, across 11 different formations, Carlsen says. Carlsen estimates US$791 million (NOK6700 million) has been saved by using formation as a barrier over the same period as a result.
Statoil is building an atlas of its results, so it can make more use of the technique and improve or standardize testing. In general, rocks which creep are those with high clay content, less than 25% quartz and under 5% carbonate.
However, it’s still an area with uncertainties. Areas which show promise for formation as a barrier don’t always prove to be so, as happened in a well on the Troll field, Carlsen says. “It may be lower pore pressure, lower temperature, lower stresses,” Carlsen says. The unexpected results will provide calibration, he says. In other cases, however, the creep can be so strong that it deforms the casing.
Sintef’s Experimental P&A Research event in Trondheim. Image from Sintef.
Aker BP also has been interested in creeping shale. It has been looking for cement bond log signals in previously uncemented intervals, then verifying the data with pressure tests. However, Tron Kristiansen, senior operations geologist, drilling engineering, Aker BP, says results can be variable, even in similar rocks. Aker BP wanted to see if it was possible to deliberately activate shale and be more certain about the end result. “By engineering it, can you get a more consistent barrier,” Kristiansen asks. Activation via pressure, temperature and a combination of both has been tried, and the best result was through a rapid pressure drop in the annulus. But more work needs to be done, he says.
Sintef has a project to understand the mechanisms that create shale barriers in order to establish methods of predicting or improving it. It has been running lab tests with core samples, including flow tests, after it thinks seals have been formed, and then takes CT scans, to see what’s been going on. Part of this work is to verify if it’s plastic deformation going on, rather than elastic – because plastic deformation would not be reversible. Ways to improve these properties would be to change pressure, temperature and use fluids to change the rock properties, says Erling Fjær, professor, department of geoscience and petroleum, Sintef. But there are still questions around the long-term effects, and if lab tests can be used to qualify shale as a barrier in the field, Fjær says.
Salt, a natural sealing formation, is also a possible natural barrier, or self-healing formation, says Bogdan Orlic, reservoir geomechanics specialist at TNO. It’s common in the Zechstein reservoirs in the northern Netherlands, and elsewhere in northwest Europe, over Permian and Rotliegendes sandstones, Orlic says, usually at about 3000m deep.
Pulling teeth (or tubes)
Where the barrier behind casing cannot be verified, cutting and pulling tubing and removing casing, a job which usually requires a drilling rig, must be done. Various alternatives are being researched, including dissolving the casing.
Astrid Bjørgum, a senior advisor at Sintef, says that by using an electrolysis reaction, in which the casing acts as one electrode, you could dissolve right through the steel. Alternatively, you could put an aggressive fluid in the well – or you could do both. “We have seen you can get high dissolution rates with strong acid and electrolytes,” Bjørgum says. At 60 degrees celsuis, acid and electrolytes used on 7in casing helped dissolve the casing in eight days and it could be less using higher temperatures, she says.
Using an electrochemical dissolution with an external, unlimited power source – power and dissolution were found to have a linear relationship – saw the 7in casing dissolved in four days using 900amp/sq m. However, conventional wireline cable is power limited, she says. Using a wireline set up, limited to 10KW, 1m of 7in tubing could be dissolved in one day, she says. This means a casing window could be created without using a rig.
When questioned about the products of the corrosion process, such as chromium, she says that they would mostly remain in the well.