JIP seeking improved health checks for remote pipelines

Monitoring the condition of pipelines is increasingly important for oil companies and regulatory authorities.

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Monitoring the condition of pipelines is increasingly important for oil companies and regulatory authorities. As oil and gas production pushes into deeper water and more remote and environmentally sensitive areas, the need to ensure pipeline integrity becomes more pressing. Better, faster feedback about the state of a pipeline also helps optimize operation.

The SmartPipe joint industry project (JIP) aims to address these issues by developing both a monitoring system that checks and reports on key parameters in close to real time, and analysis tools for turning this data into meaningful information when compiling the history of a pipeline’s condition.

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The SmartPipe JIP has set itself the goal of monitoring a range of parameters relevant to pipeline operability.
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The project is led by the Sintef research institute and Sicom, a company specializing in subsea communication and integration. Its budget of NOK 43 million (around $8.4 million) is funded by the Research Council of Norway and six operating companies: BP, ConocoPhillips, Eni, Gassco (the operator of much of Norway’s gas pipeline network), Shell, and Total. Also contributing are Roxar, Bredero Shaw-owned Thermotite, and Force Technology. Sintef is being assisted by the Norwegian University of Science and Technology (NTNU).

Monitoring based on pigging and ROV inspection often is expensive, performed infrequently, and may require shutdown of the system, so the new approach fits in well with the “e-field” philosophy for optimizing production operations.

The two business cases chosen for study under SmartPipe are an in-field flowline and a subsea-to-shore flowline, reports project manager, Ole Øystein Knudsen. All the equipment must have a working life of 20 years and be qualified to operate in water depths of 1,000 m (3,281 ft).

Parameters to be measured are wall thickness, stress/strain, temperature, pressure, pipeline position, flow mode, and leakage. When the project started in 2006, the initial focus was on identifying sensors and systems suited for the purpose. The selected sensors – ultrasound devices, strain gauges, accelerometers, and thermo-elements – all work in a non-intrusive fashion and can be sourced readily off-the-shelf.

Power and communications cables are available also, but since cables tend to be vulnerable, the sponsors are keen for alternatives to be developed, i.e. local power generation and wireless communications. So the JIP has chosen two local power solutions: a thermo-electric generator exploiting the temperature differential across the pipewall in cases where the pipeline contents are hot; and a seawater battery using a cathode in conjunction with a sacrificial anode to generate power.

Local power generation will be limited to a few milliwatts, so both sensors and communications elements have been selected for low power consumption. Power consumption also has been optimized by choosing appropriate intervals for the different measurements.

Since corrosion is a slow process, the measurement of wall thickness has been set at once every one million seconds (11.5 days), while the interval for measuring vibrations is 10 times/second. If sufficient power is available, the operator can request sensor data when needed.

The selected wireless communication method is electro-magnetic waves transmitted along the pipe wall. Communicating data via the pipe wall has been done before, but not on the scale required for SmartPipe, Knudsen points out. Electro-magnetic waves have only a limited range, so their use needs to be combined with a multi-hop solution – re-transmission nodes along the line – to achieve the required range. Depending on specific circumstances, a combination of wireless and cable could be used – for example, sending data in wireless mode up the pipeline to the wellhead and then by cable through the umbilical.

Mounting of the equipment package and survival of the hardware, especially during the pipeline installation, are other key challenges. The package is designed to be attached to the line at the field joint connecting two pipe sections during the field joint assembly process. It will be mounted before the polypropylene coating is applied. As this coating is applied in melted form, the package must withstanding high temperatures.

Further critical moments come during reeling and installation when the pipeline is exposed to pressures which can cause up to 3% plastic deformation of the steel.

Having identified solutions to the various challenges, the project now is preparing for a laboratory demonstration next year. A demonstrator unit will be constructed from two pipe spools welded together to give a total length of 24 m (78.7 ft). Four hardware packages will be installed on it, plus a sacrificial anode. Mounting of the hardware packages and coating of the pipe spools will take place at the Thermotite plant in Norway, where the assembled unit will undergo simulated reeling on a test rig before the main test program starts at Sintef.

For data processing the project is working with three existing programs:

  • For fatigue analysis, the Simla program developed by Marintek
  • For corrosion analysis, CorposAd, which was developed by Force Technology
  • For assessing local effects for fracture risk, the LINKpipe program developed by NTNU and SINTEF.

These now are being integrated and adapted to handle continuous sensor data input and data exchange. Knudsen sees good potential for drawing enhanced value by using them in a coordinated fashion.

Next year’s test program will conclude the three-year project. But thoughts are already turning a possible second phase during 2009-12, in which the technology will undergo pilot testing on a live pipeline, says Knudsen. Following that, it will then be ready for commercial use.

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