Electromagnetics: de-risking oil and gas discoveries

Materials World magazine
1 Feb 2014

A UK start-up is exploiting electromagnetic mapping to de-risk its North Sea gas prospects. Melanie Rutherford learns from Fred Gyllenhammar and Alastair Murray why Stavanger Petroleum Ltd is set to be the first in the UK to use the technology on existing discoveries yet to be fully appraised.

Electromagnetics (EM) is nothing new in the science world. Well log resistivity has been a key hydrocarbon indicator since the 1920s, and EM tools were developed by the Russians more than 40 years ago for offshore mapping. Seismic surveying using sound, like ultrasound in medicine, has long been the preferred tool of the oil and gas industry to map subsurface layers and structures, but controlled-source electromagnetics (CSEM) is now being heralded as the new kid on the geological block.

While seismic surveying can identify subsurface structures, uncertainty remains as to whether these contain any significant volume of hydrocarbons. Drilling of dry wells is a costly way of determining this, so many exploration companies are now looking to 3D CSEM to reduce this uncertainty.

Since its introduction in the oil and gas industry in the late 1980s, CSEM’s credentials have slowly grown, although a sprinkling of failings have led to divided opinion on its value as an appraisal tool. This may seem strange, as resistivity measurement was the first wireline log to be developed and used, and today, all exploration wells are logged with a resistivity tool to identify hydrocarbons. Although CSEM has yet to make its mark on British waters, UK focused start-up Stavanger Petroleum could change all that. Having secured six licences with several undeveloped oil and gas discoveries in the North Sea in the 27th licencing round in 2012, Stavanger – the brainchild of geologist Fred Gyllenhammar and materials scientist Alastair Murray – is spearheading CSEM in an attempt to secure vital investment for exploration and de-risk its North Sea prospects.

Murray explains, ‘Sand filled with salt water is a very resistive body, so it will give you an incredible signal. While seismic survey methods detect structures in the subsurface, CSEM detects horizontal resistivity and, therefore, whether the structure has the potential to be hydrocarbon filled.’ The technique involves towing a high power source of EM energy by boat over a grid of receivers placed 1–3km apart on the seabed. By measuring the refracted energy from subsurface layers, areas of high electrical resistivity are identified. So far, CSEM has proved successful at depths of up to 3,500m and at a poorer resolution than seismic, which is effective to around 6,000m. In 3D CSEM, a grid of receivers records both inline and azimuth (angled) data, allowing variations in resistivity across three dimensions to be mapped, offering increased coverage and resolution.

While Murray says it would be erroneous to categorise CSEM as a direct hydrocarbon indicator, ‘it does give absolute certainty as to where there are no hydrocarbons present’. Integrating CSEM with existing seismic data allows greater understanding of subsurface geology and can result in discoveries of areas that had been undetected by initial seismic interpretation. ‘As we already know the vertical resistivity of our mature gas fields and that there are hydrocarbons present, we’re using CSEM as an appraisal tool to give greater certainty on the likely volumes of hydrocarbons in place,’ Murray explains. ‘As a secondary result of this approach, we will de-risk all the regional prospects that previous operatives have worked on using the very strong, but more traditional, toolbox. We’re not discounting any of the existing techniques, what we’re about is enhancing them through integration with an extra dataset. If it’s used in the right way, CSEM is a very powerful tool in reducing risk and enhancing shareholder value.’

CSEM: a history
While CSEM was first introduced to the oil and gas industry in the 1980s, it was not until more than decade later that its use alongside seismic data was recognised by industry majors The story stems back to 2002, when EM technology was being used by scientists at the University of Southampton, UK, to study highly resistant volcanic sills in the Atlantic. Fred Gyllenhammar, CEO and founder of Stavanger Petroleum, explains, ‘They developed some big seabed instruments to determine the resistivity of the sills at mid-ocean ridges, by measuring the refracted voltage from a huge electrical signal sent though cables attached to a boat on the surface’. Later, in 2002, Statoil wondered if the same technique could be used on oilfields, which have a resistivity similar to that of the volcanic sills. The Norwegian supermajor contacted the team and used the method to test its own oilfields off the coast of Angola. With results proving positive, it developed its own system and later founded spin-off company Electromagnetic Geoservices (EMGS), specialising in CSEM interpretation and data integration.

Murray first came across CSEM when he was working at Canamens Energy, a UK-based oil and gas exploration and development company. As Innovation and Technology Director, Murray was involved in various projects for oilfields, including Kraken, in the North Sea. It was at Canamens that he met Gyllenhammar, who was working there as Project Manager Geoscience at the time. Murray explains, ‘As a data geek – I’m not a geologist, more a physicist – when I, as a non-expert, looked at the seismic data for Kraken, I couldn’t see anything. The mapping was severely unconvincing to me. Clearly there was a large body of sand and a lot of oil, but I found the whole discussion around well placement quite problematic.’

In an attempt to make sense of the seismic data, Gyllenhammar and Murray sought the advice of several CSEM companies, including Offshore Hydrocarbon Mapping (OHM) in Aberdeen, which was later merged with EMGS. Murray admits, ‘They were actually a bit sceptical about whether EM would be able to differentiate between these kind of thicknesses of sands (less than 20 metres).’ But nonetheless, the pair returned to Canamens convinced they had the solution and tried to sell the concept to the other directors. ‘At the time, Kraken had two very successful wells and were preparing for a third appraisal, and management saw no need for additional data,’ says Murray. ‘The third well turned out to be drier than dry. It was then that the shareholders suggested “we should try your idea”.’

Through OHM, the partnership (under the project management of Dr Ben Clarke, now of Nexen) acquired CSEM test lines across Kraken. ‘Gradually we built confidence and acquired more lines, and we started to get the feeling that there were a lot more hydrocarbons on the other side of the fault.’ After subsequent drilling, their hunch was confirmed. But what should have been a turning point for Murray and Gyllenhammar turned out to be a dead end. ‘The interesting thing was that neither Canamens or its partner companies really understood what we’d done with the CSEM,’ says Murray. ‘They were classical geologists, so it was never written up.’

Meanwhile, Gyllenhammar had built a database of all the undeveloped discoveries on the UK and Norwegian shelf – a total of 400 discoveries, representing eight billion barrels of recoverable reserves. ‘Alastair and I decided to build a company around trying to get hold of these kinds of assets, and farm into others who were sitting on discoveries but were not able to get funding to go forward,’ explains Gyllenhammar. ‘Then the UK 27th licensing round came up and we decided to put in an application for eight licences.’ In 2012, the pair were awarded six licences, making Stavanger Petroleum one of the UK’s most successful newcomers.

One of the most promising of the undeveloped discoveries is Blue Sky, the licence for which was previously owned by Danish company Maersk. ‘They had several other producing fields at the time – I think Blue Sky was too small for them at that point, so they were happy to relinquish it,’ says Gyllenhammar. But while CSEM is ideally suited for use on Blue Sky, the field’s history raises concerns for potential investors. ‘They immediately wonder what you are seeing that Maersk didn’t – and why they didn’t see it,’ says Gyllenhammar. ‘Whereas in fact, Blue Sky has a lot of gas, it just didn’t have the same value when it was discovered in 2001 that it does today. We also have much newer and better seismic tools than were available just a few years ago.’

While investors may be asking questions, UK licence body DECC was won over with Stavanger Petroleum’s approach in the application process. ‘I think we won DECC’s confidence when we said, “actually, for what we want to do, dry wells are just as important as discovery wells”,’ says Murray. ‘Because with the addition of CSEM you have absolute calibration, and with that comes much greater confidence and understanding. We’re using what many perceive as an exploration tool, but we’re using it more in an appraisal sense, with a secondary aspect of de-risking exploration. And we’re de-risking the entire portfolio – we’re not just focusing on discoveries and regional prospects, and that’s how we sold it to DECC.’ Murray adds that the company will look to use 3D CSEM to understand the entire play within the cluster of blocks. ‘That is an extremely good way to unlock value for the UK. Not only will it greatly increase understanding of those fields, but it also offers increased confidence of volumes, which drives successful appraisal wells. Essentially, it’s a way of adding value to the national bank of the next phase of oil and gas exploration.’

Failures and limitations
Why, then, if CSEM has been around for so many years, has it not received wider recognition in the industry? As with any technology, it is not without its pitfalls. Aside from the aforementioned depth constraints, a lot of early work on CSEM concentrated on finding out what was beneath certain types of basalt basement. Murray explains, ‘The basement can have a huge impact on the data – if your target is too close to the basement, then the noise reflecting from it can overwhelm your ability to differentiate between high and low resistivity.’

Murray and Gyllenhammar are selective about where they choose to explore, looking to mature, shallow fields hosting tertiary (Palaeocene or Eocene) prospects and discoveries within those formations. But with few published studies to back up the use of CSEM as an appraisal tool (Kraken was one of the first), the technique has divided the exploration community. Furthermore, its early use in frontier exploration led to a string of failures that have not been forgotten. Murray refers back to the 1980s, when Bergen exploration company Rocksource was founded and led by Johnny Hesthammar – ‘a visionary who convinced everyone that CSEM was the answer to everybody’s prayers. But there were abundant failures with it as a pure exploration tool, particularly in frontier areas, because you aren’t able to calibrate the data with that for seismic. Generally, there are many formations that can generate a positive anomaly, such as freshwater or limestone fill in a sandstone reservoir. But in the negative sense, only a saltwater filled reservoir is conductive and will yield a good negative signal.’

Murray believes in a so-called Ikea approach – ‘buying the flatpack of someone else’s data and then hiring a cabinet maker to put it all together. We’re not claiming to be the best integrators, but we’re using the best integrators. And we’ll be using the best acquirers and the best modellers. It is this kind of data management that reduces risk.’

In that respect, CSEM boasts some impressive figures. ‘When integrating EM data with existing seismic data, current statistics shows that when CSEM says there are no hydrocarbons present, there is an 86% chance that it is correct,’ says Gyllenhammar. ‘Drilling one dry well will cost around US$15m and a CSEM survey on that area costs just US$1–2m. If the CSEM data helps you discount, say, three out of six wells, even if two are successful and one is not, you have quickly saved around US$30–40m.’

Worldwide use
Stavanger Petroleum is not the only exploration company to have tapped into CSEM. Since 2002, Statoil’s EMGS spin-off has helped companies across the world to conduct multiple surveys in frontier basins and bypassed fields in mature areas, in an effort reduce exploration risk and improve drilling success rates.

Murray explains, ‘Some companies use it incredibly widely, but often it’s not written up. Word on the street is that for the last eight or nine years, Exxon Mobil has not drilled any offshore wells offshore without using CSEM, though it uses its own equipment and integrates the data in-house.’ He adds Shell and Maersk to the list, both of which recently signed contracts with EMGS, and Mexican stateowned Pemex has also contracted EMGS to run the largest EM survey to date, in the Mexican part of the Gulf of Mexico.

Stavanger Petroleum is working closely with EMGS and Aberdeen-based geoscience consulting firm RockSolid Images (RSI), which also offers CSEM interpretation services. Should the company secure investment to carry out CSEM on its North Sea prospects, it will be the first to do so in the UK sector. ‘If we are successful, I think many more companies will use it in the UK for the shallow prospects, as well as more extensively worldwide,’ says Gyllenhammar.

Whether the technology will one day be as widely accepted as seismic remains to be seen. ‘It’s like marmite – people either love it or hate it,’ says Murray. ‘But generally speaking, neither side really understands it. Some people get really excited about it, but the actual physics is essentially the same as that for acquiring a wireline log, which the Schlumberger brothers were doing 100 years ago – the first tool they developed was in fact the resistivity measurement. It has only been around in its CSEM form since the 1980s, so it’s definitely still an evolving technology and there is still an awful lot of test work to be done, particularly on the mathematics. Integrating such a huge dataset with seismic requires not only a lot of know-how, but also a lot of computing horsepower.’

CSEM may not have convinced everyone, but Murray believes it won’t be long before the odds start to swing in its favour. ‘We might get through one more licensing round without people really waking up and smelling the roses. But once people see a successful well, everybody will say, “Hang on a minute, why aren’t we doing that?” The oil industry is incredibly conservative and smaller start-ups working in these kinds of fields generally aren’t in a position to take up any new technology – only the supermajors have the resources to do it. But some of the best conversations we’ve had have been with supermajors, because they absolutely get what we’re trying to do.

‘We had hoped to have acquired the initial CSEM survey by now, but there have been some equipment limitations,’ admits Murray. ‘We have been looking at particular tool called Shelf Express, which is probably the one we understand the best and is the most powerful in that niche. Unfortunately it has been in use in southeast Asia for the last year, but a second one is being commissioned in April 2014.’

But the ball is steadily rolling for Stavanger Petroleum. Statoil recently confirmed installation of a gas export line across Blue Sky, due to be laid down in summer 2014, and is also considering installing a recycled platform that currently sits on the Norwegian shelf. With concern rife over the limited reserves in the North Sea, Stavanger and its pioneering work with CSEM could prove to be a game changer for the UK oil and gas industry.

The promote licence: how it works
Learn how DECC is helping small start-ups compete alongside multinationals. Melanie Rutherford delves deeper into UK oil and gas licensing in our latest Tumblr blog – read it at tumblr. materialsworld.com