Shooting sharper seismic

New seismic technologies are helping BP’s geoscientists to ‘see’ more clearly beneath the earth’s surface to identify hydrocarbon resources. Nina Morgan explains the crucial role seismic technology is playing in keeping BP ahead in successfully finding and developing oil and gas fields

In a geographical sense, they may be worlds apart. But in geological terms, Jim Keggin, BP geophysical advisor stationed in Cairo, and Scott Michell, a geophysicist with BP’s exploration and production technology group based in Houston, share a common problem. They both work in areas where salt accumulations below the surface act as a distorting lens, making it difficult to gain an accurate picture of the geology below.

‘Attempting to see through Mediterranean salt,’ says Keggin, ‘can be like trying to see through the textured glass in a bathroom window. The images are noisy and fuzzy.’ Michell agrees. ‘To get a clear vision through salt,’ he explains, ‘you need to find a way to look at the target object from several different angles and then combine the data. The breakthrough is that new seismic acquisition and processing techniques being developed in BP are really helping us to do this.’

BP's new seismic technology helps wells to reach oil-bearing reservoir zones below salt canopies

This is all good news. ‘But,’ notes Keith Nunn, distinguished advisor for geophysics in Sunbury, ‘finding better ways to see through salt is far from the only seismic problem that we face. Continuing to improve the design, acquisition and processing of seismic data to provide increasing accuracy and resolution, whether it be for exploration or for appraisal, development and production of discovered reserves, is a major challenge.‘

In order to discover the new resources needed to maintain increasing levels of oil and gas production, BP is turning towards geologically more difficult areas where the hydrocarbon targets are deeper and obscured by complex geological overburdens – conditions that make obtaining good seismic images more problematic.

It’s a challenge BP has faced up to with relish, as Michelle Judson, BP’s geosciences technology unit leader in Houston, explains. ‘Given the pressing business need facing BP with our portfolio of assets we decided that we needed to shift our stance from viewing seismic as a commodity, to seeing it as a technology that was worth investing in significantly. The results of this strategy, combined with the designation of subsalt seismic imaging as a technology leadership area for the company, are already paying dividends in the form of better imaging in many difficult regions of the world.’

BP believes that the ongoing effort to develop better ways to see below salt can potentially deliver very significant value over the next decade or so. But that’s not all. It could also pay greater dividends in the future because many of the technology advances associated with subsalt imaging could also be used in areas where salt is not a problem.

By making several parallel passes with a survey boat, a 3D 'cube' of seismic data can be generated

Adapting the azimuth

‘One of BP’s great strengths,’ observes Peter Carragher, head of discipline for exploration in Houston, ‘lies in its ability to take the very deep principles of seismic surveying and apply them to very specific local needs in different parts of the world. As a result, BP has proved to be very successful at deriving maximum bang from its seismic research bucks.’

Technologies already in common use to solve different problems are being successfully adapted to improve imaging below salt layers. Multi-azimuth seismic, or MAZ, is a good example. MAZ draws on and extends the principles behind normal three-dimensional (3D) seismic surveys. In a conventional 3D survey, a seismic boat towing long cables or ‘streamers’ behind it, sends out sound signals and collects the signals reflected back from the geological structures below the seabed. The vessel travels back and forth, shooting and collecting data along many parallel lines, resulting in seismic data generated along lines just 25 metres apart. This produces a 3D volume, or ‘cube’, of data (see diagram below) that can be ‘sliced’ in any direction to provide a picture of the subsurface from many different views. For a MAZ survey, between two and six 3D surveys are recorded over the same area in quick succession, but at different angles – or azimuths – to one another. This results in a grid of closely spaced seismic data lines.

Click the link below to view a panel about seismic surveys: 'Azimuth advantage'

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By processing the individual surveys separately and then combining the data, it is possible to look at the same spot from many different angles. The result, says Keggin, is better illumination of the subsurface. ‘It’s like trying to look under a chair,’ he notes. ‘You get a better view of what’s there if you step around the chair in a circle and look below it at different angles.’ And from the data processing point of view, handling surveys in this way makes it easier to reduce ‘seismic noise’ and damp down the effect of ‘multiples’ – unwanted signals that bounce around in the water layer.

Click the link below to view a graphic of the Messinian layer in the Nile Delta

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MAZ is proving to be a valuable tool to BP in its exploration in the Nile Delta region offshore Egypt, where it has proved difficult to see below the Messinian layer – a thin, but very complex layer of anhydrite salt located around three kilometres below the surface that tends to scatter seismic waves.

‘Historically, deep imaging in this area has been very tough,’ says Keggin. ‘But a two-azimuth MAZ survey shot in 2003 over the Polaris prospect encouraged us to go on to acquire a six-azimuth survey to aid in the development of the Raven discovery.’

The results of the Raven survey led to the decision to go one step further and invest in a ‘Mega-MAZ’ survey to look at further exploration targets in the Nile Delta area.

Looking through lenses

Although Mega-MAZ is due to play a key part in BP’s Nile Delta forward exploration programme, it is not necessarily the answer in areas like the Gulf of Mexico, where the salt tends to be more massive and very complicated, and distorts subsurface images. In this part of the world, new acquisition techniques are the rising stars. One is wide azimuth towed streamer (WATS). Another is a deepwater ocean-bottom seismic technique which BP refers to as ‘Nodes’, which uses recorders – or nodes – located on the seabed, rather than the cables employed in conventional ocean-bottom seismic acquisition. Both were developed by BP and, like MAZ, both build on existing technology and are designed to collect wide azimuth data.

WATS relies on a standard 3D seismic survey configuration of receivers mounted on towed streamers to collect data. But instead of a single sound source mounted on the recording boat, additional source boats are deployed. The sources are fired sequentially, and the receivers record data from each in turn. The use of multiple sources makes it possible to collect information from many different angles. Combining and then processing the data results in a clearer picture of the geology below salt. The first WATS field trial was carried out over the BP-operated Mad Dog field in the Gulf of Mexico in 2005.

‘WATS technology,’ says Michell, ‘will also be useful for solving appraisal and development problems in other types of complex and difficult areas, and may have exploration applications too.’

In contrast, Nodes appears to turn the standard acquisition method on its head. Rather than using a large array of receivers on streamers towed behind a seismic boat to record data, the Nodes approach uses a relatively small number of receivers placed on the sea floor. These record the seismic wavefield from a dense grid of shots generated by a single source boat sailing over the area.

'Nodes' uses a seabed array to detect different types of waves reflected from the subsurface

The nodes themselves are specially designed geophones – receivers that collect various types of seismic wave data from the subsurface. The hardware is adapted from instruments more commonly used to study earthquake seismology, and never before applied in an oil and gas arena. Each node is like a small ‘space probe’ and incorporates its own power source, computer and clock to allow it to act as an autonomous recording unit.

To carry out a survey the nodes are placed in a suitable pattern on the sea floor by an industry-standard remotely operated vehicle (ROV), a small, surface-controlled submarine. While a source boat sails back and forth over the area, the nodes sit on the ocean floor listening and collecting data. After the survey they are recovered by the ROV, and the data are retrieved and processed. The first Nodes field trial, involving 900 nodes, is currently taking place over the BP-operated deepwater Atlantis field, situated in over 2150 metres of water in the Gulf of Mexico.

The development of Nodes is a testament to the power and value of BP’s seismic modelling capability (see panel ‘Try before you buy’ below).

Link to panel on seismic computer modelling

Click links below to view panel on seismic computer modelling

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‘This may seem a strange approach,’ says John Etgen, senior advisor for seismic imaging in Houston. ‘But we have discovered that collecting data in this way makes the computations much easier. By taking advantage of a mathematical theorem, known as reciprocity, which relates to how wave propagation works, we can mentally interchange the role of the source and the receiver to make it appear as if there were 900 sources on the sea floor and more than a hundred thousand receivers on the surface.’

The hope is that Nodes will prove to be a cost effective way to acquire wide azimuth data and carry out detailed seismic work in relatively small areas of less than 400 square kilometres. The technology should be particularly useful where there are many offshore production platforms or other infrastructure that could cause towed cables to get tangled. Eventually, Nodes may even prove useful for 4D seismic applications (see below).

Enter the fourth dimension

Meanwhile, in areas like the North Sea, the addition of a fourth dimension – time lapse – to seismic observations is becoming more common practice in BP’s producing fields.

‘The beauty of 4D seismic is that it gives you a good picture of the spatial distribution of the oil that has been produced, and changes in the pressure front in the reservoir over time,’ says Dave Whitcombe, seismic network lead and senior advisor in 4D, based in Aberdeen. ‘It is supplementing and complementing conventional production logging and really creating a whole new game in field surveillance. This enables us to understand a field’s behaviour better, and to predict future production with more accuracy.’

The most common method of acquiring a 4D survey is to shoot a fairly conventional, but repeatable, 3D survey at time intervals that are, typically, two years apart. By subtracting one 3D image from the other, complexities due to geology are removed, leaving a relatively simple image which can be interpreted as the changing position of the oil-water interface in the reservoir over the time between surveys. This provides a useful insight into reservoir behaviour and helps to identify areas where oil has not been produced.

Since the late 1990s when BP began using 4D systematically in the North Sea, the technique has proved to be a powerful tool to aid in reservoir management. Now in the Valhall field offshore Norway, BP has taken 4D a step further, by setting up a permanent life-of-field seismic (LoFS) system recorder (Frontiers, December 2003). This consists of a series of seismic receiver stations mounted on a cable on the sea floor, connected to the Valhall platform. During a survey, seismic data are transmitted from the receivers to the platform, and relayed from there to shore via an optical cable.

Because each receiver station includes three geophones, as well as the usual hydrophone, both pressure and shear waves in the subsurface can be recorded.

‘The shear waves are particularly good in helping us to see through gas obstructions in the overburden,’ Whitcombe explains. ‘Currently a source boat shoots a survey over the installation every three months. This frequency of acquisition opens up the possibility of making a ‘movie’, where each 3D image forms one frame, to monitor changes and help to spot the more subtle effects in the reservoir.’ The quieter environment on the sea bed also results in a better ratio of seismic signal to noise.

While LoFS is more costly than conventional seismic acquisition, it has positive payback over time, adds Whitcombe. ‘Permanent 4D installations become entirely attractive in big fields with substantial remaining hydrocarbon reserves where the data have the potential to impact the siting of lots of wells.’

LoFS installations that are being planned include the giant Azeri and Chirag oilfields in the Caspian Sea (see feature 'Setting the standard', this issue) and the Clair field on the margins of the Atlantic to the north of the UK.

Ideas in abundance

Impressive though they are, MAZ, WATS, Nodes and permanent LoFS recorders are by no means the only seismic innovations BP has developed. ‘When it comes to participating in industrial societies,’ notes Etgen, ‘BP tends to be a fairly major presence. This is not because BP has a monopoly on brain power – it’s more a question of drive and confidence that our people are going to come up with good things, and that over the long term, those good things are going to lead to commercially viable activities.’

A further explanation, and a key to BP’s continued success in the seismic field, lies not only in how seismic is used, but also in developing an integrated approach that includes the other core subsurface disciplines such as geology, reservoir engineering and petroleum engineering, adds Mike Bowman, head of discipline for appraisal, with responsibility for the development and production geoscience community, based in Sunbury. ‘It’s the integration with the other disciplines that really delivers the value from the seismic images we can now produce.’

With BP’s reputation for leadership in seismic technology well established in the industry, Tim Summers, seismic imaging technology director based at Sunbury, is convinced that there are still many more developments to come. For example, BP’s massive in-house computing capability – BP’s Houston campus houses one of the most powerful computing centres in the world (Frontiers, April 2003) – already offers significant scope for translating geophysical ideas into real practical applications, and continually increasing computing power is becoming more economically available. But most important of all, he says: ‘The ideas have not yet run out. Given the essential role seismic imaging already plays in BP, and the great potential it holds for further development, this points to very exciting times ahead.’

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