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Ocean bottom seismic – improving cost and reliability

Monday, July 19, 2010

Stingray Geophysical of the UK is aiming to reduce the cost and improve the reliability of permanent seabed seismic monitoring, thereby making seismic permanent reservoir monitoring practical

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When permanent seismic monitoring first came onto the market, many people thought that it would become the standard way of monitoring reservoirs – and that it would replace towed streamer for 4D seismic.

But so far, only 4 systems have been installed since 2004: by BP on Valhall and Clair in the North Sea and ACG in the Caspian Sea; with the fourth, by Shell on the Mars field in the Gulf of Mexico, unfortunately destroyed by hurricane Katrina.

Stingray Geophysical of the UK is on a mission to make seismic Permanent Reservoir Monitoring (Seismic PRM) the “solution of choice” for maximising the effectiveness of reservoir management offshore and especially in deep water.

Martin Bett, CEO of Stingray, believes that seismic PRM could become mandatory in time. “Increasingly we will see governments and the agencies that control natural resources mandating technologies and techniques that deliver a systematic data-driven approach to maximising total recovery.  This is the only route for the oil and gas business to be truly sustainable,” he says.

The Stingray system uses fibre-optic cables, both for the hydrophones and accelerometers themselves, as well as for the communications between them.

A big advantage of fibre is its reliability. For normal electronic components, the mean time between failure is typically measured in thousands of hours. For fibre-optic components the unit of reliability is hundreds of years, Mr Bett says.

“The failure rate of Stingray’s fibre-optic hydrophones is 1 in 18,300 years,” he says. “It hasn’t broken yet.”

There are possibilities that a system could be damaged, for example by a dragging ship anchor or fishing activities, but this only applies in shallow water. Mr Bett believes that the chances of damage to the system are so low “we can almost discount it, especially since the arrays are typically buried for protection and coupling with the earth.”

Even if a sensing cable is severed, Stingray’s Fosar Seismic PRM system is usually configured in a bi-directional mode.  This means that the system will continue to work, with no degradation in system performance, as each sensor can be accessed by two alternative routes.

Stingray’s Fosar system has been substantially tested, undergoing 10 field tests with no failures over the last 6 years. A military system, from which the Fosar system is derived, was installed for 11 years and still working perfectly when it was retrieved.
 
The biggest weakness in any such system is probably the connections between different fibres – so, to reduce this risk, the system is designed with as few fibres and connections as possible, he said.

Also, if you are using conventional electronics, you need to bear in mind that the voltage required increases with the length of cable. For example, if you have 200km of cable, you need “several kilovolts” of power to reach the full length of it, he says. And the higher voltage is more likely to cause equipment failure.

“Permanent 4D will also give you a better resolution,” he said.

The company is so sure that companies will get long term benefits that it is offering to put together schemes whereby the equipment and installation costs of a Fosar system are financed,  then oil companies pay either an annual fee or a fee per survey – so the system is leased rather than purchased.

“It’s very very reliable and very sensitive,” he says.  

Perhaps expectedly so as the technology was originally developed at UK government research centre DERA (Defence Evaluation and Research Agency) for detecting submarine movements during the “Cold War”.

The company can fix 20,000 to 30,000 sensors on 200 or 300km of fibre-optic cable and acquire measurements on each sensor several hundred thousand times each second when pulsing laser light into the array.  

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With higher quality  data about the reservoir, it is possible to improve production and minimise cost and risk.   A more detailed view provides a deeper understanding of the reservoir, in particular about its heterogeneity which evolves as it is produced. “All reservoirs are more heterogeneous than at first thought – and normally they become even more so as they are produced,” he said.

In a typical reservoir situation the reservoir engineer has a great deal of information about the areas in and around the wells, but reservoir characteristics between the wells are typically extrapolated from well-centric data.
 
By mapping attributes aerially across the reservoir, 4D seismic typically delivers a return on investment that can be “50 or 60 times” greater.

However this doesn’t necessarily make it easier to go to management and ask them to invest – because they want to know about the benefits they will get today. “The NPV calculation applies a full weighting to upfront costs and significantly discounts benefits that will occur in the future,” he said.

Mr Bett estimated that the cost of just 1 misplaced subsea well could pay for the costs of a Seismic PRM system – and of course there are additional benefits from having a better understanding of the reservoir and being able to spot small changes going on in it.

A seabed system can also collect 4-component data, unlike a towed streamer. It can be used in obstructed areas – e.g. doing a survey on an area where access with a 3-D streamer vessel is difficult or even impossible.

“If we can address the upfront cost and the reliability, we’re going to be onto a winner – and that’s what Stringray is all about,” he says.

The operations manager of Stingray is a subsea installation engineer, focused on making the seabed installation work, rather than the seismic aspect of PRM, he said.

The Valhall system has 140km of cable, with 28,000 sensors in it.

Mr Bett said that independent Availability Reliability & Maintainability (ARM) studies for specific Fosar configurations indicate that after 15 years we could still expect (with a 90% probability) to have in excess of 98 per cent of sensors still working.

The dynamic range of a Stingray’s Fosar hydrophone is about 180dB, compared to 120dB range for a conventional electrical hydrophone. The sensitivity  works out at about 1,000 times greater (because the db scale is a logarithmic measurement).

It is also possible to use such systems on land, although it hasn’t been done so far, he said. The economic benefits would appear to be less attractive because the cost of installing such systems on land and drilling wells is significantly lower.

“Nevertheless, we are approached by a number of companies each year to ask if we would build a land based system – and maybe we will…” he says.



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» Stingray Geophysical Ltd
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