Ocean bottom seismic – helps increase recovery “up 3-5%”
Feature Articles, Aug  14  2009 (Digital Energy Journal)

- By installing ocean bottom seismic cables, you can increase overall recovery from your field by 3-5 per cent, says Samir Seth of PGS

By installing permanent seismic receivers on the sea bed, and feeding the data into reservoir models, to help build up a continuous picture of how the reservoir is changing during production, you can improve decision making and this should typically increase overall recovery by 3-5 per cent, said Samir Seth, VP fibre optics business development, commercialisation and new ventures with Norwegian seismic company PGS, speaking at the April OilVoice / FindingPetroleum Forum in London.

With ocean bottom permanent monitoring seismic, a vessel on the water surface can fire down seismic shots into the subsurface, and the reflections can be recorded on the seabed, with the data sent back up to surface. This is typically done every 6 months.

Of course, the capital cost of installing permanent seabed equipment is not insignificant. So the challenge is often finding ways to justify them.

This is tricky, when you don’t know how much value it will generate. For example, the ocean bottom seismic can show up bypassed oil, which isn’t finding its way into the reservoirs. “Most of the gains are unexpected,” he said. One can’t quantify the exact amount of bypassed oil in advance.

The technology is too new to have been widely adopted, so statistical data showing success in a large numbers of fields does not exist yet.

Purchase decisions are often made on the basis of a calculated ‘net present value’ – ie an estimate of how much extra production can be achieved from having the system.

But companies would be better off treating the investment decisions in the same way as exploratory oil wells, where they have become comfortable with the financial risks involved.

“When you explore for oil, you say - I'll spend $100m going to the Arctic - if I find oil, then I'll spend $1bn to get $5bn,” he said.

In a way, this too should be treated as exploring for oil in existing fields. In fact the finding risks are lower as one knows hydrocarbons exist in those structures. And as production infrastructure such as pipelines and gathering stations already exist, overall production costs are lower for these ‘finds’.

PGS showed models showing what kind of increase in production you would need in order for a project to be worthwhile with different levels of investment – however it stresses that all fields are different and customers should put their own models together.

The system is initially finding most market acceptance for large fields, he says. “Typically larger fields with long lifetimes left have been the first ones we've worked on.”

The system is also answering growing demands within companies for better reservoir models.

“We’re seeing interest in complex reservoirs and where there is a high requirement for repeatability in seismic surveys,” he said.

The system is probably going to be more expensive than using towed streamer if you are just planning to do one survey – but as you get to the 2nd and 3rd survey or more, then the cost of a permanent ocean bottom cable solution starts working out to be much cheaper, he said.

A towed streamer system can be more flexible, and cover a wider area, he admitted. If the marine seismic companies renew their technology quickly and spend the capex on new streamers as soon as new technology becomes available, then it may be easier to implement new technology there too.

For example, PGS is updating its fleet with state-of-art Geostreamer technology nowadays. That said, in Permanent systems using fiber optics, the dry end which has the brains of the system is on a platform, so it is easy to update as technology and improves (compared to electrical systems with in-sea electronics).

However one of the biggest advantages of ocean bottom detectors is that the lifecycle time of the survey (from deciding to do it to updating the fluid model using the results) can be a lot shorter. “We are taking about a way to do four component seismic on demand,” he says.

One advantage of ocean-bottom seismic receivers is that it can be much better to compare the results of one survey with another.

There are options to the density of the cables – a 1000m distance is considered “sparse” and 300m apart “dense”.

Better view

Oil companies have good information for the rock [formation] close to the well, because of the all the logging tools which can be lowered directly into the wells, but “as you go deeper in the reservoir it’s difficult to predict what's going to happen,” he says.

“We think seismic, perhaps in future in conjunction with electromagnetics, is the only way to see deep into the reservoir,” he says.

Having seismic detectors on the ocean bottom mean that the quality of data recorded can be much higher, because there is less noise than doing seismic recording on the ocean surface. “The seabed is calmer than the sea surface so your readings will be better.” “Smaller changes can be detected in the reservoir as the repeatability is better.”

Having a more granular view of the subsurface means that you can see a lot of useful information much more clearly – including bypassed oil, waterflood fronts, and unswept parts of the reservoir.

You can also see parts of the reservoir which might be obscured using conventional surface seismic – eg if there is a platform in the way of the vessels.

The aim is to see how a water flood is moving through the reservoir, so you won’t be taken by surprise when it hits the well.

Sometimes a seismic survey can be messed up by short term events (eg solution gas coming out of the subsurface) – but you’ll never know unless you do the same survey again shortly after, he stressed.

“For example, if solution gas comes out - it might appear that the water table has risen. If that's the day you did your seismic, you might have to wait 5 years before you know if the water table has risen or if its solution gas coming out.”

Technology

The “wet end” – the system that goes under water – is completely passive (ie it does not need any electrical power). It is expected to last for 20-25 years.

Since the technology is new, PGS has not yet been able to test it on the seabed for 20-25 years, so it has done what it sees as the next best thing, testing it using DNV’s “qualification procedures for new technology.”

“No-one could find a reason to say it wouldn’t work,” he said.

The sensors are made of fibre optic. It uses a sensing coil and a reference coil, and measures the difference in impact of light on those coils, due to the received seismic wave.

The fibre optic cables can carry a large amount of data, so there can be many sensors in the array. The different channels can all be sent at different frequencies, like on an FM radio.

All the demodulation (separating the signal from the carrier wave) is done on the surface, rather than at the ocean bottom.

This means that most of the complex data processing and electronics is on the surface – where it can be easily repaired or updated, if something better comes along.

The seabed array could be far, for example 40km away, from the platform where the data is processed, with no loss of data quality. Alternatively, the data can be collected on a separate floating structure away from the platform.

The first system was trialled in the North Sea in 2003, and showed it made comparable data to a retrievable ocean bed seismic cable system. Further successful tests have been made in 2006 and 2008.

How often

Typically towed streamer (surface) seismic surveys are made every 3-5 years, he said. But with ocean bottom cable, it can be done every 6 months, Mr Seth says, if it is worth detecting small changes.

“If the change is too small there’s no point in doing a repeat,” he said. “But with this system you can see smaller changes.”

The surveys can be done more often if there are faster changes to be monitored.

One delegate also involved in ocean bottom seismic receivers said he had seen trends of surveys being made twice a year.

See a video of Samir Seth’s presentation

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