Aging offshore production systems and infrastructures can be given extended lifecycles with today’s creative methods of remediation, standardization, and preventative techniques, say a group of engineers presenting at the recently held Offshore Technology Conference in Houston. In the current low-commodity-price environment, energy operators and service companies are finding that necessity is truly the mother of new creative innovations and interventions for aging assets.
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Image from Pertamina Hulu Energi ONWJ. |
For example, Pertamina needed secure hydrocarbon flow between two offshore northwest Java platforms, but the carbon-steel pipeline was aged to the point of increased risk for a potential loss of integrity. The company initiated a study to evaluate the remediation benefit of using the existing pipeline as casing for conduit for new Thermoflex flexible pipeline, provided by Polyflow Global LLC, which could be pulled through the casing to connect the two platforms.
During the project, nearly 10 km of flowline was pulled through from the tie-in flange below the emergency shutdown value at one platform and received at the same elevation at the other platform. The process did not require a modification to the existing riser bends.
“We attached a cone with holes attached to the flexpipe so we could pull through the flexible pipeline at 20m to 40m per minute using a winch and ropes,” said H. Yananto, an engineer with Pertamina Hulu Energi ONWJ. “We used a reel on one platform and a winch on the other and both were placed topsides.”
After installation, the new infrastructure was hydrotested with treated seawater pressurized from 250 psi to 500 psi, which represented 1.4 times the maximum allowable operating pressure, to ensure safe operations. The low capital cost and low maintenance cost technique rehabilitated the pipeline without removal and replacement of the existing pipeline. At the conclusion of the project, Pertamina realized a 56% savings of capex.
Meanwhile, Statoil recommends high levels of standardization of asset components, so when lifecycle extension or remediation is desired, less engineering of custom units and equipment is required.
As part of its corporate strategy, Statoil launched its “subsea factory” concept. The company adopted the philosophy as a result of recognizing that the offshore industry is continuing to move processing facilities from topsides to subsea. In fact, Statoil itself has deployed subsea pumps and separators at its Troll Pilot and Tordis assets. This year, Statoil plans to deploy the world’s first subsea compressors at its Asgard and Gullfaks fields. Because the cost of such subsea developments has increased by a factor of 2.5 during the past decade, the company will establish a “Business-Agreed Standardization” model on subsea processing interfaces and modules with suppliers to achieve plug-and-play functionality. The goal is to increase the profitability of subsea developments and increase subsea processing volumes.
“About 50% of our costs are in subsea equipment,” says Rune Ramberg, a chief engineer for Statoil. “We are facing rough times and subsea is under pressure, so to speak. We must reduce costs by standardization, simplification and re-use, which will reduce both risk and delivery time. We want to involve our suppliers in our global initiative for standardization of topsides, umbilicals and subsea equipment. Together, we can be leaner, faster and smarter.”
Elsewhere, Jos Bronneberg, an engineer with SBM Offshore USA, recommends that companies prepare, within their initial planning, for the sour gas that is eventually produced from sweet oil reserves. The souring is a result of conditions that encourage sulphate-reduction bacteria in the reservoir through seawater flooding and temperature gradients. Sour gas (H2S) content in reservoir fluids not only affects all the systems through which it passes, but also the working environment for personnel on the floating production facilities. In fact, as project life cycles are extended, the problem becomes exacerbated.
However, relatively simple provisions, many of which must be planned at the start of field development, can be added to the project design to allow the production facilities to operate safely during the entire design life.
For example, operators should ensure they have equipment in place for a mitigation method that takes place upstream of the reservoir. This would include units for the sterilization of injected water, such as electro-chlorination, or the removal of sulphate from seawater through the use of sulphate-removal membranes. To mitigate the souring of the reservoir itself, operators should be prepared to inject bactericides to depress the formation of bacteria, or inject nitrates, which will stimulate the growth of nitrogen-reducing bacteria, which can starve out sulphate-reducing bacteria.
“Initial planning should include high-pressure systems, the capability for future injection of H2S scavengers, and operational practices to deal with pyrophoric material at the beginning of the project,” says Bronneberg. “This will reduce costs when the oil field eventually sours. Managers have to be prepared to handle 50 to 100 parts per million of H2S, because all fields will eventually have that.”
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