By Edward Naranjo, Emerson Process Management, Rosemount

Over the last 30 years, the use of FPSOs (Floating, Production, Storage, and Offloading) and other Floating Storage Units (FSUs) has emerged as a key technology to produce oil and natural gas from subsea fields. These vessels can be deployed quickly, and advances in FPSO technology have allowed them to operate in increasingly severe environments and deeper water, and to handle higher pressure and more wells. Not surprisingly, the share of offshore production installations comprised by ships is growing, accounting for 30 percent of the UK Continental Shelf production, in one instance [UK Health and Safety Executive (HSE), 2014].

Despite the increasing number of floating production installations, controlling hydrocarbon releases and reducing the risk of fires and explosions remain key concerns for FPSOs. As higher temperature, higher pressure reserves are harnessed, exploration and production equipment is subjected to greater stress. According to the UK Health and Safety Executive, FPSOs and FSUs have a higher rate of hydrocarbon releases than fixed installations [HSE, 2014].

Most FPSO risk assessments identify the turret system as one area of potentially highest risk [International Association of Oil and Gas Producers (OGP), 2006; HSE, 2014]. Turret systems are the structure from which production fluids from the flexible risers are transferred to the process plant on the vessel by a swivel or other fluid transfer system. Turrets maintain the vessel on station through single point mooring and allow rotation of the vessel to adopt the optimum orientation in response to weather and current conditions. In most cases the vessel can freely rotate through 360o. An FPSO turret system comprises three main systems: the turret; a fluid transfer system (FTS), a multi-path swivel to transfer the production fluids to the process plant on the vessel; and an intermediate manifold known as the turret transfer system (TTS) that links the turret and the fluid transfer system. All parts of a turret system are shown in Figure 1 below.

Figure 1. FPSO Diagram Showing Cross Section Through an Internal Turret
Figure 1. FPSO Diagram Showing Cross Section Through an Internal Turret

As with other offshore systems, FPSO turret systems can be subject to degradation in service. Corrosion, abrasion or fracture, and changes in material properties can lead to loss of containment of hydrocarbons. Likewise, hydrocarbon releases can also result from poor maintenance practices, insufficient operational controls, or damage from dropped objects. Regardless of failure mode, ignition of released hydrocarbon can cause or contribute substantially to a major accident.

According to a report commissioned by HSE [Wall et al., 2002], the consequences of a turret explosion could be the following:

  • Structural damage or plastic deformation of the turret
  • Fatality to all individuals involved in the initial blast
  • Serious injury confined to turret and immediate surrounding areas
  • Local escape and evacuation routes potentially destroyed or damaged
  • Process area inventories potentially vulnerable to exposure to fire, which with escalation could lead to explosion

According to the same report, the frequency of hydrocarbon gas releases within the turret system is approximately 2 x 10-2 per year and that of turret explosion is 2 x 10-4 per year. The gas release frequency is similar to that of reciprocating compressors (7.1 x 10-2 per year) and centrifugal compressors (1.1 x 10-2 per year) used in offshore and onshore installations [OGP, 2010], and other process equipment used for the handling of fluid.

Because control measures may fail, it is essential for turret systems to have such measures in place as flame and gas detection and fire deluge arrangements. Ultrasonic gas leak and point combustible gas detectors can be installed to monitor the turntable manifold and the fluid transfer system, which has high pressure dynamic seals. In offshore production in the UK, many of the reported incidents between 1995 and 2000 have been associated with the turret transfer system in internal turret designs. The combination of ultrasonic gas leak detection with point gas detectors is particularly effective, since leak detectors respond to the source of the release, while gas detectors help assess hazard severity. Other areas to monitor are the swivel access structure and the gas export swivel.

In some instances, it might be necessary to monitor path of travel to protect worker accommodations, many of which are close to the turret system in internal turret designs, as well as the process plant. In such cases open path detectors could be beneficial. Similarly, flame detectors are required to monitor the main turret, the multi-path swivel stack of the fluid transfer system, and the turntable manifold of the turret transfer system. In the fluid transfer system, it is not uncommon to site one or more flame detectors on each story of the swivel access structure.

Floating structures for production, storage, and offloading have been used safely and reliably over many years. Turret technology has played a key role in mining fields, as turrets have become larger and more complex to handle increasing levels of production and the particular process conditions of individual wells. Nonetheless, with higher throughput and operation in increasingly severe environments, addressing the potential of hydrocarbon gas releases becomes an important element in accident mitigation.

One tool to reduce the risks of escaping gas or process fluids is flame and combustible gas detection. Ultrasonic and combustible gas detectors may arrest the escalation of an incident, while flame detectors can offer early warning of jet fires. Since no one detection technology is 100% effective, the use of a combination of ultrasonic gas leak detection, gas detection, and flame detection increases detection efficiency and offers the most effective means to reduce the consequences of hydrocarbon releases. More information on gas and flame detection solutions can be found here.

How have you set up your gas and flame detection systems to help ensure the best possible safety coverage for your application?



HSE. 2014. Offshore Oil & Gas Sector Strategy 2014 to 2017. London, UK: HSE Books.

International Association of Oil and Gas Producers (OGP). 2006. Guideline for Managing Marine Risks Associated with FPSOs, Report No. 377. London, UK: OGP.

International Association of Oil and Gas Producers (OGP). 2010. Risk Assessment Data Directory, Report Vol 434-1. London, UK: OGP.

Wall, M., Pugh, H.R., Reay, A., and Krol, J. 2002. Failure Modes, Reliability and Integrity of Floating Storage Unit (FPSO, FSU) Turret and Swivel Systems, Offshore Technology Report 2001/073. Abingdon, UK: HSE Books.

Hi, I’m Ed Naranjo, and I’m your Analytic Expert today. You probably know that Emerson’s detection products are about securing the safety of people and property. Quickly and reliably. But, who determines the safety of safety equipment?

dnvThat was my tricky way of telling you that the GDU-Incus ultrasonic leak detector that you’ve been hearing so much about has now received two important approvals, which verify its safety and appropriateness for its applications. One is the highly respected Det Norske Veritas (DNV) type approval. This DNV certificate further confirms the GDU-Incus is suitable for use onboard marine vessels including liquid natural gas (LNG) and liquid propane gas (LPG) carriers, crude oil tankers, and floating production, storage, and offloading (FPSO) units, all of which can suffer loss of production, or worse, in the event that a gas leak is not detected quickly or at all.

Detecting gas leaks in marine environments is challenging for traditional detectors because they require the accumulation of a gas cloud in order to alarm. Extreme weather and wind on vessels and platforms can prevent a kcgas leak from being detected, allowing the incident to escalate. Since the GDU-Incus responds to the ultrasound produced by the leak, its performance is unaffected by these conditions. That’s why it’s ideal for marine applications. Receiving this approval means that the detector withstood the rigorous testing required for the DNV certification, which further demonstrates the quality and robustness of the ultrasonic gas leak detector.

On top of that good news, this month, the GDU-Incus adds South Korea Certification – K-Mark – to its impressive list of approvals. The testing was performed through the South Korean Testing Laboratory.

These approvals assure potential users that the GDU-Incus has undergone rigorous testing and has been determined to meet the highest quality standards. These assessment processes are built upon scientific research and recognized by regulators, insurers, and major clients throughout the world. Good news for your safety.


Hello. I’m Eliot Sizeland and I’m your Analytic Expert for today. Maybe I should say detection expert because I’d like to talk about air cooled heat exchangers, which are a classic example of an application environment where traditional means of leak detection are generally inappropriate. These heat exchangers have hundreds of potential leak points and are normally located in elevated positions far above the ground or deck where air movement is considerable. Since most traditional leak detectors, like point and open path IR, catalytic beads, and electrochemical sensors, are dependent on the formation of a large localized gas cloud for detection, these devices are unable to detect leaks in the high pressure, high temperature, and rapid air movement in such applications. Due to speedy gas dilution, point and line of sight detectors rarely detect gas in concentrations which are sufficient to trigger alarms. In addition, line of sight detectors may suffer from persistent issues with misalignment due to high vibrations caused by the fans used in the heat exchanger.

RAI.GDUIncusFortunately, ultrasonic gas leak detectors are ideally suited to monitor wide areas in high pressure gas process equipment. One such example occurred on an offshore platform in the North Sea in the United Kingdom. The operator’s heat exchangers used line of sight detectors to detect gas leaks, but the vibration from the fans themselves tended to make the detectors lose alignment and initiate unwanted alarms. A GDU-Incus from Emerson was employed to maximize coverage area with none of the problems of traditional detectors. Because they are triggered by ultrasonic sound versus a gas cloud, they are unaffected by the air movement and vibration from the fans.

Determining if ultrasonic gas leak detection (UGLD) is the best solution, however, requires a survey and ultrasound mapping. The survey makes recommendations to establish detector positioning, sensing range, minimum and maximum leak rates detectable, alarm levels, and recommended alarm delay settings. The single most important factor for detection is the difference between the sound level of a potential gas leak and the normal plant operation for UGLD to work.

Ultrasonic noise can be generated in a number of ways that may lead to inappropriate positioning or alarm condition such as mechanical noise, process generated ultrasound, or electrical equipment. The main reason for undertaking a survey is to measure the ultrasound in the operational plant. Where new build installations are considering the use of UGLD, assumptions of background sound levels are made based on a wealth of experience from live plant studies.

RAI_coolerUltrasound mapping is undertaken using a calibrated device that measures the operational plant sound level in the detector’s frequency range. A scaled plot of the target area is divided into a 5m grid, with lines running North-South, East-West. At each intersection the sound level is measured and a polar plot constructed, which then can be amalgamated into an overall background ultrasound plot for the target area (see Figure 1). The detection area is then matched to the plant process and can be verified on commissioning.

In most cases, UGLD is specified to detect a leak rate of 0.1 kg/s. That said, the main challenge with specifying a single leak rate is that not all 0.1 kg/s leak rates are detectable by UGLD. Rather than specifying a single leak rate, a refined technique is to find a suitable detection radius (meters) that ensures the desired leak rate is detected while maximizing the range of leak diameters (gas leaks) to be covered. The images below are presented for illustrative purposes.


Figure 2 stretches the detection range to the maximum, but only a tiny window of gas leaks is detectable. By contrast, Figure 3 shows a significantly increased rate of detectable leaks, but sacrifices detection range. For many installations general area coverage (maximum range) is not appropriate, and it is important to tailor the range to the target risk.

With an ultrasound map in hand, plants with air cooled heat exchangers can detect leaks in extreme weather conditions with no loss of detection capability. Click HERE for more information on ultrasonic gas leak detection in this application and click HERE for more information on the GDU-Incus and its technology.

Ensuring safety for personnel and protection of facilities and equipment is a top priority for all industrial plants. A critical element of this is the effective detection of dangerous flammable and toxic gases and vapors and their potential ignition. However, building an effective safety monitoring solution is a complex task as there is no single system or technology that would be the solution for every plant. There are several fundamental choices available in detection technologies. Jonathan Saint from Emerson Process Management, Net Safety recently published an article with Facility Safety Management that addressed the available options and how to build a solution that works for your plant while saving lives, property and dollars.

An effective solution requires three levels of detection. Safety systems that deploy a diverse range of safety technologies can counteract the serious impacts of gas leaks and the potential for fire and explosions. The article entitled Three Levels of Detection Safety Monitoring: Combining Technologies for Reliable Results addresses the different types of gas and flame detectors, including point type, line of sight, ultrasonic and flame detectors, and their strengths and weaknesses and how to build an optimal solution using an effective combination of these. Read the full article HERE. Following is an excerpt:

Safety systems that deploy a diverse range of detection technologies can counteract the serious impacts of gas leaks and potential for fire and explosions. A combination of ultrasonic leak detectors, fixed gas monitors and flame detectors, is particularly effective because they’re complementary and cover the three detection defense levels.

The first stage is the immediate leak stage, which has the greatest opportunity for fast and effective mitigation; the second is during the gas cloud formation or accumulation stage, which is a very serious safety condition; and the third is during the ignition state, which can be catastrophic.

Ultrasonic detectors are often installed outdoors to cover wide areas with challenging detection conditions. Point detectors should be installed at or near known high-risk gas leakage points or accumulation areas to provide information on the level of gas present in these areas. Open-path gas detection systems are more effective at plant or process area boundaries. They monitor the plant perimeter and provide an indication of overall gas cloud movement in and out of the facility.

The movement of gas clouds throughout the facility is tracked by monitoring the output signals of all the gas detectors within the safety system. Optical flame detectors monitor wide areas for IR or UV energy related to the ignition of a gas source and provide instant alarm condition back to notification and mitigation systems.

A variety of challenging factors affect the performance of these technologies; location (indoors/outdoors); air flow; gas properties (type, density, buoyancy); environmental conditions like temperature and humidity; background conditions (false alarm sources); and obstruction. Best practices for each application will be different, but it’s critical to perform proper HAZOP analysis and identify the sequence of events leading up to an accident.

Every safety engineer that is committed to safeguarding personnel, plant and productivity, and employing a system that provide comprehensive, tiered coverage can yield optimal results before an escalated incident occurs.

To read the full article, click HERE.

Are you providing the optimal safety coverage within your applications?