Among the priorities that emerged from discussions between the Centre, offshore operators, service companies, the supply chain, and academia were development of rigless P&A techniques that could provide alternative types of barrier materials to cement, or improve the cement placement process to deliver a strengthened barrier; eliminate the need for tubular removal; enable multi-string logging; and improved flow path modeling.
During 2017, the Centre initiated its first Call for Ideas for transforming well P&A, and it is currently supplying funding to four of the 48 proposals put forward. Malcolm Banks, Wells Solution Centre Manager at the OGTC, outlined progress on some of these projects and others that the Centre is supporting.
Offshore: What facilities can the OGTC offer to support innovations in P&A?
Banks: The OGTC is publicly funded and its role is to accelerate technology development – it’s basically a solutions centre that works collaboratively with offshore operators, the supply chain, developers, entrepreneurs, and others. The Centre has no labs or research capability in-house, but we are building a National Decommissioning Centre north of Aberdeen with University of Aberdeen that will have verification and testing capability for P&A. Once that’s up and running we can help provide access to sponsors to get additional testing done in that environment. So promising technology developers will be able to do their stuff in-house, or go to a third party for testing. Some universities in the UK can also provide this capability.
Offshore: What are North Sea operators typically looking for in terms of breakthrough technologies, and what were the OGTC’s criteria for selecting the four initial P&A projects for sponsorship?
Banks: In the field of well P&A, the industry is telling us that its main priorities are looking for new barrier materials and downhole sealing methods. When we launched our Wells P&A Call for Ideas, proposals were invited via an online portal. Following a first-stage assessment and ranking by a panel of reviewers 10 were selected, with each of the developers being invited to make a 10-minute presentation to a panel of industry representatives from Repsol-Sinopec, Shell, and Total. They chose the top four and the Centre put in place arrangements for supporting those projects. We also tried to assist some of the rejected applicants, in certain cases advising them to reduce the scope of their programs or putting them in touch with other organizations that could help them mature their ideas, in case we might be in a position to provide funding in the future.
There are two main ways the OGTC initiates projects: Direct and Portfolio projects. The latter originate from specific technical-themed requests by industry, while with Direct Projects the developer comes to us with an idea asking for help to take it forward. Or an operator may approach us about a technology they have heard of which they would like to progress – but with the OGTC’s support, to reduce their element of risk involved. When the Centre agrees to provide part-funding, it is on the understanding that the developer is committed to advancing the idea to an eventual field trial.
Offshore: How many operators are open to that idea in practice?
Banks: Eight or nine field trials have been performed on some of the technologies supported by our Wells programs. In the P&A domain, Interwell’s technique has completed two field trials in the UK for Spirit Energy and BISN’s bismuth alloy technique has undergone various applications. Because UK operators see the challenge of abandonment looming, they do appear more willing to take a chance on field trials on something that can help bring down their costs. Typically, this would be on low-risk wells which are nearing end of life, so if the technique doesn’t work, it’s not a negative commercial impact.
Offshore: The OGTC has repeatedly stressed the need for rigless deployments as one of the prime means of cutting P&A costs. To what extent is this achievable?
Banks: The industry sees rigless P&A as a bit of a holy grail, implying that all P&A tasks could eventually be performed without the need for the bigger tools that require a rig. To do that, you would need not to have to recover tubulars in their entirety or to recover casing before you place a barrier. Interwell’s thermite plug – one of the projects the Centre is supporting – can be installed via wireline to make the steel and rock fuse to create a barrier. However, it will be very challenging if all wells could be done 100% in that way in future.
Offshore: Is it necessary for drilling contractors to engage in collaborations with the developers of these techniques that you are supporting? And is some sort of supervision needed to ensure HSE compliance offshore?
Banks: Yes, our aim is to accelerate technology development, so it is important that we gain the ‘end user’ collaboration. Legislation varies from country to country. The UK is driven by a goal-setting regime in which the regulator sets expectations. It is then up to the offshore operator to demonstrate alignment. Oil & Gas UK (OGUK) issues industry P&A guidelines for cementing, pressure testing, and verification requirements and new technologies are benchmarked against these.
Offshore: Can you provide an update on some of status of the P&A projects the OGTC is supporting?
Banks: These are some of the most promising.
Biogrout is a technology developed by the University of Strathclyde in Scotland that uses enzymes to repair or improve cement barriers in wells that are being P&A’d. Biogrout’s low viscosity and nanoparticle size allows it to penetrate and seal ultra-small spaces. The principle involves putting naturally-occurring soil bacteria downhole in liquid form for placement in cement which has cracks, blocking migration pathways in these wells and thereby preventing the flow of hydrocarbons to surface. As the bacteria grow and then degrade, they form a calcium carbonate layer that creates a natural closure in the cement. The process is simple to apply via low-pressure pumping, with no need for a rig.
This is an example of technology transfer, building on work the university has been doing with the construction industry. In our case the question is, will the technique work in a downhole environment? As you go deep down into the wellbore, the temperature increases and so does pressure in the fluids. Tests are in progress at elevated temperatures and pressures in Strathclyde’s lab facilities to see whether the bacteria survive. If they do, the next step would be downhole trials. Poor-quality cement in the annulus impacts around 30% of wells, and the OGTC believes that roughly 10% of these could benefit from the application of Biogrout. Potentially it could bring savings of 5-20 days per well in terms of pulling casing.
Aubin’s reverse scale squeeze concept is designed to deliberately clog formations. Often when wells are put into normal production, the flow is accompanied by deposition of sodium bromide or calcium bromide scale in the tubulars. But if you can create scale in the reservoir itself, this could form an alternative barrier. Or if the well is producing unwanted water, the chemical could be pumped down the reservoir to block the pores through which the water is flowing.
Stavanger-based Well-Set is working with the OGTC to investigate the potential for magnetic rheology in well cementing. The technique (patent-pending) uses magnetorheological (MR) cement to form a barrier in an annulus. The cement is suspended between two magnetic fields until it sets, with no risk of gravitational migration. It means that casing annuli can in theory be plugged between defined depths via a wireline or coiled tubing deployment, without the need to cut or pull casing. This could improve the accuracy of cement placement and strengthen cement integrity, with the possibility to set shorter or cross-wellbore abandonment plugs.
BiSN’s Wel-Lok M2M technology (developed in Houston and Warrington, UK) employs a thermite heater and a bismuth-based alloy to form a seal in the wellbore, thereby installing a barrier across tubing and casing. This is seen as an alternative to traditional elastomer seals, resin, and cement. The alloy has a relatively low melting point of around 150°C (302°F) and can be delivered downhole in pellet form. A heat reaction is then triggered and the viscosity of the alloy, which is similar to water, allows it to flow easily into cracks and fissures in the wellbore, following which it sets and expands.
This is one of the few technologies we are supporting that has already been commercialized, with various deployments already offshore the UK, Norway, and in the Gulf of Mexico. The very first commercial application was as a barrier in tubular strings for preventing flow from the water zone lower down, however we were looking at it more for abandonment purposes – flowing out through multiple casing strings or tubulars to achieve isolation. P&A trials are being staged for various operators in the North Sea and include monitoring of the barrier capabilities. The longer-term goal is to qualify the technology as a permanent P&A barrier. If validated, this could reduce the need for tubular removal across a large proportion of UK wells, being wireline deployable from a platform or intervention vessel.
Other promising programs supported by the OGTC include technology developed by SPEX in Aberdeen that removes casing and any associated cement back to the formation, allowing installation of a permanent barrier. This allows the remainder of the casing to be left safely downhole and reduces the number of cuts and pulls needed to seal off the well. BHGE is working on a tool that can provide cement logging through multiple casing strings in one run, as opposed to conventional solutions that deliver logging behind only one casing or tubular. Historically it has sometimes been necessary to remove tubing and then run a log to check whether the cement behind the casing string has the right integrity. If BHGE’s development is successful, it could cut the cost and time associated with removing casing in order to check barrier integrity. Another aim is to see whether the tool could be moved across multiple zones. It’s very much a piece of R&D which we supported in the first phase, and which came up with some interesting results. •
Trials progressing of thermite plug
Interwell in Stavanger has developed an e-line deployed tooling system that comprises a heat shield followed by a barrier tool, positioned in the cap rock. An electric signal activates the tool causing a controlled, slow-burning, exothermic reaction at extreme temperatures. The reactants melt through the wellbore and surrounding materials to bond with the cap rock formation. After cooling, a solid and impermeable barrier forms which extends across the full cross-section of the well, sealing both vertically and horizontally, with the cap rock formation restored to its original integrity. The company has been developing the process since 2012, its aim being to create formation-to-formation barriers across multiple drill pipe strings as an alternative to cement plugs. By February this year the company had completed 16 plug settings in 11 different wells.
Following initial tests in wells onshore Canada, the technique was tested for the first time in Europe last year in an onshore gas well in Caythorpe, northern England, operated by Spirit Energy and with support from the OGTC. Willem Boon, Spirit’s Principal Well Engineer, said: “Although offshore operators are often reluctant to be the first to try new technology, we would say that as long as it’s been properly assessed and goes through the right process, Spirit is more open to working with the supply chain on testing and introducing new technology and new methods.
“In this case we have taken a phased approach to trialling Interwell’s technology…building up to a first trial offshore in late spring this year on Spirit’s Audrey gas field in the UK southern North Sea. For this test we used the thermite plug at one of the wells before plugging and abandoning the well as usual. That trial is now complete and we’re still assessing the results. Initial data suggested it wasn’t as effective as it had been when we tested it onshore, but we’re continuing to work with Interwell to understand those results and to determine how we then proceed. But it’s a technique and technology that has huge potential, and with every test we learn more about how it can be used.”
