Costs drive a trend to open path
Published: 01 October, 2008
Brian Jones, UK manager for Norwegian fire detection company Autronica has noticed that the trend within the offshore industry has moved from infrared point gas detectors towards open path detectors.
Jones attributes this development to costs and the lack of detailed requirements for the actual placement of open path gas detection equipment. “The specifier will still have to design a plot plan, but this will involve only a limited number of open path gas detectors where a larger number of infrared point detectors would normally have been required.
We currently see that open path H2S detectors are becoming increasingly popular as hydrogen sulphide is increasingly encountered because many wells are sour now. Most wells in use are older or previously exhausted, and newly enhanced technology enables exploration companies to drill deeper.”
In one large project in the northeast Caspian Sea in the Republic of Kazakhstan, says Jones, very high levels of H2S deposits are being found – around 18 per cent – and exploration companies are concerned that this gas, which exists beneath the earth’s surface, will rise to the surface as a result of drilling.
Apart from being corrosive and rendering some steels brittle, H2S leads to sulphide stress cracking. This is a type of spontaneous brittle failure in steels and other high-strength alloys occurs when they are in contact with moist hydrogen sulphide and other sulfidic environments.
Jones describes the potential danger of H2S clouds as one of the triggers that have forced exploration companies to install more intelligent detection systems. “People onboard rigs wear H2S detectors but apparently these are not always accurate. Also, by the time the gas is detected, the person carrying the detector has usually inhaled too much of the substance to survive.”
An open path detection system which is set up in a grid offers a good chance of detecting a gas. Although point detectors are deemed to be more accurate, Jones emphasises that the two types of detectors are best used in combination with each other and not as a substitute for one another. Having a wide variety of detection equipment on the offshore facility is extremely important and Jones recommends that accoustic detectors should always be a part of this, as these finely tuned microphones listen for potential leaks.
In any detection system a probability of failure analysis is built-in, and therefore a wide variety of detectors helps towards building a better picture of what actually happens during an incident. Jones explains that the analysis of all different inputs is extremely complex, and this added complexity can sometimes cause glitches. “When more technology is added you enter the realm of certified safety. The individual instrument might have been tested in a controlled environment, but not as part of complete operating system. And this is what the industry is debating at the moment.”
In order to lower cost of ownership and spending on maintenance, many operators have the main control room onshore and all platform functions are monitored from there. This control centre will usually function as the communications hub for between 10-15 different platforms. Diagnostics information and data from the various assets are fed back to shore by Internet-type protocols. Although this technology has been available in the processing and automotive sector for years, the offshore industry has taken slightly longer to adopt Fieldbus technology. And for good reason, says Jones, as it requires proven technology for a safety environment.
When carrying out plant maintenance in the past, a facility would have to close down for two weeks and maintenance would have been pre-planned. Nowadays, because operators are aiming to reduce life cycle and maintenance costs, periodic maintenance is often reduced in favour of unplanned and online maintenance. Furthermore, many companies are now installing upgrades online to take advantage of the high prices of oil – a process shutdown can mean susbstantial revenue losses.
A major gas supply company operating in the UK is implementing an online, offshore integrated control system. The company will effectively have both the new and the old system running together until the newer version has proven itself to operate without any glitches, explains Jones. “Information gathered by these integrated systems comes in many shapes. They can be one-directional or bi-directional, or operators may just read information from the sensors.”
The HART Protocol (Highway Addressable Remote Transducer) is one popular method of remote monitoring of assets in this sector of industry. The protocol is a digital industrial automation protocol which can communicate over legacy (4-20 mA) analogue instrumentation wiring, sharing the pair of wires used by an older system. Previously, if the calibration on a device required adjustment, someone would physically have to go to the device, interrupting the production process.
HART enables the operator to send commands rearranging a field device without process disruption. This type of technology has now been proven on a number of developments, explains Jones. “Autronica’s AutroSafe Fire and Gas system provides the same functionality as the HART Protocol, using a loop-based solution with intelligent protocol interfacing of the detectors.”
Another factor that drives up cost for operators is the sheer number of rules and regulations offshore fire protection equipment has to comply with and the differences in standardisation all over the world.
“Complying with maritime standards is probably the most complicated. Mobile drilling rigs and semi submersible drilling vessels and FPSOs – as opposed to the fixed platforms – have to adopt maritime standards which don’t apply for the fixed facilities.
“For example, mobile platforms that have been designed for European waters may be contracted to drill in South America, which could result in the fire protection equipment onboard having to be changed significantly. Obviously this is a huge cost for the operators.”
These facilities are often mounted on ship or platforms which are hired on a contract basis. The contract hire companies want to keep their rental rates as low as possible, and therefore the vessels are designed with the bare minimum of specifications. Should a vessel or rig be moved from South American into European waters the chances are high that a number of fire protection devices will have to be added to meet European requirements. Jones adds that this can be a very complex and expensive process.
“However, most manufacturers are abreast of that now. It just takes some time to obtain the right approvals. We have for instance just launched a new product for the maritime industry, and although we have had it physically working for a year, it will take us at least another year to get the approvals in place.”
