Quasar 2 – New Flare Stack Monitoring System

The new flare stack monitoring system from LumaSense Technologies is designed to monitor pilot flames and flared gases for elevated flare stacks. Additional applications include: Gas assist flares, Staged flares, and Offshore flares. Quasar 2 is available in “Basic” and “Advanced” models.

Safe flare operation and environmental protection require reliable and accurate flare pilot monitoring. Generally, all flare pilots are monitored with thermocouples. However, thermocouples fail due to thermal shock, extreme heat and vibrations during flaring events. The requirement for pilot monitoring beyond the normal life of pilot thermocouples has driven the market need for alternative methods and installation of redundant methods of pilot monitoring in addition standard pilot thermocouples. Regional flare governmental permitting rules driven by environmental protection, health and safety guidelines for global flare operation have had a large impact on the increasing market need for IR pilot monitoring systems.

The E²T Quasar 2 series are monitoring and detection instruments designed for continuous duty monitoring of pilot flame and flared gases from flares. The base system provides low-cost basic flare pilot monitoring capabilities. The advanced model has an intensity meter with 2 set points that allow monitoring of both the pilot and flaring status signals from the same unit. Additional add-on features are available for a configurable product to meet a wide range of client flare types, monitoring requirements and budget. High Resolution sight-through optical system and selection of various spot sizes enables the Quasar 2 system to be positioned as far as 1/4 mile (400 m) from the stack being monitored. Alignment on the target is accomplished through bead and notch aiming and signal amplitude in combination with a stable M-4 heavy duty swivel mount. Custom electronics adapt to target movement, varying luminosity and most climate conditions. The alarm delay circuit can be adjusted for a specific location or application, eliminating false alarms from temporary loss of signal due to intermittent flames, adverse weather and wind.

The system is complete with internal cooling base, air purge tube and swivel mount. An optional M-8 pedestal stand allows for easy stable system mounting. With over installations at over 550 petrochemical facilities worldwide, customers know they can trust LumaSense E²T line of petrochemical infrared sensors.

LumaSense Technologies, Inc.

Published on Aug 1, 2018

For more information, visit: https://info.lumasenseinc.com/q2

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Subsurface Data in the Oil and Gas Industry

Probing beneath the Earth’s surface for exploration and hazard mitigation

Drilling for oil and gas is expensive. A single well generally costs $5-8 million onshore and $100-200 million or more in deep water.1 To maximize the chances of drilling a productive well, oil and gas companies collect and study large amounts of information about the Earth’s subsurface both before and during drilling. Data are collected at a variety of scales, from regional (tens to hundreds of miles) to microscopic (such as tiny grains and cracks in the rocks being drilled). This information, much of which will have been acquired in earlier exploration efforts and preserved in public or private repositories, helps companies to find and produce more oil and gas and avoid drilling unproductive wells, but can also help to identify potential hazards such as earthquake-prone zones or areas of potential land subsidence and sinkhole formation.

Mapping the Subsurface 1: Regional Data from Geophysics

In the 21st century, much is already known about the distribution of rocks on Earth. When looking for new resources, oil and gas producers will use existing maps and subsurface data to identify an area for more detailed exploration. A number of geophysical techniques are then used to obtain more information about what lies beneath the surface. These methods include measurements of variations in the Earth’s gravity and magnetic field, but the most common technique is seismic imaging.

Seismic images are like an ultrasound for the Earth and provide detailed regional information about the structure of the subsurface, including buried faults, folds, salt domes, and the size, shape, and orientation of rock layers. They are collected by using truck-mounted vibrators or dynamite (onshore), or air guns towed by ships (offshore), to generate sound waves; these waves travel into the Earth and are reflected by underground rock layers; instruments at the surface record these reflected waves; and the recorded waves are mathematically processed to produce 2-D or 3-D images of subsurface features. These images, which cover many square miles and have a resolution of tens to hundreds of feet, help to pinpoint the areas most likely to contain oil and/or gas.

A typical setup for offshore seismic imaging. Image Credit: U.S. Bureau of Ocean Energy Management.2

Mapping the Subsurface 2: Local Data from Well Logs, Samples, and Cores

Drilling a small number of exploratory holes or using data from previously drilled wells (common in areas of existing oil and gas production) allows geologists to develop a much more complete map of the subsurface using well logs and cores:

  • well log is produced by lowering geophysical devices into a wellbore, before (and sometimes after) the steel well casing is inserted, to record the rock’s response to electrical currents and sound waves and measure the radioactive and electromagnetic properties of the rocks and their contained fluids.3 Well logs have been used for almost 100 years4 and are recorded in essentially all modern wells.

  • core is a cylindrical column of rock, commonly 3-4 inches in diameter, that is cut and extracted as a well is drilled. A core provides a small cross-section of the sequence of rocks being drilled through, providing more comprehensive information than the measurements made by tools inside the wellbore.5 Core analysis gives the most detailed information about the rock layers, faults and fractures, rock and fluid compositions, and how easily fluids (especially oil and gas) can flow through the rock and thus into the well.

By comparing the depth, thickness, and composition of subsurface rock formations in nearby wells, geoscientists can predict the location and productive potential of oil and gas deposits before drilling a new well. As a new well is being drilled, well logs and cores also help geoscientists and petroleum engineers to predict whether the rocks can produce enough oil or natural gas to justify the cost of preparing the well for production.7

A box containing 9 feet of 4-inch diameter core from the National Petroleum Reserve, Alaska, showing the fine-scale structure and composition of the rock layers being drilled. Image Source: U.S. Geological Survey.6

Data Preservation

Preservation of subsurface data is an ongoing challenge, both because there is so much of it and because a lot of older data predate computer storage. A modern seismic survey produces a few to thousands of terabytes of data;8 state and federal repositories collectively hold hundreds of miles of core;9 and millions of digital and paper records are housed at state geological surveys. For example, the Kansas Geological Society library maintains over 2.5 million digitized well logs and associated records for the state.10 Oil companies also retain huge stores of their own data. Preserving these data, which cost many millions of dollars to collect, allows them to be used in the future for a variety of purposes, some of which may not have been anticipated when the data were originally collected. For example, the shale formations that are now yielding large volumes of oil and natural gas in the United States were known but not considered for development for decades while conventional oil and gas resources were being extracted in many of the same areas. Archived well logs from these areas have helped many oil and gas producers to focus in on these shale resources now that the combination of hydraulic fracturing and horizontal drilling allow for their development.

Data for Hazard Mitigation

Oil and gas exploration is a major source of information about the subsurface that can be used to help identify geologic hazards:

  • Since 2013, the oil and gas industry has provided more than 2,500 square miles of seismic data to Louisiana universities to assist with research into the causes and effects of subsidence in coastal wetlands. For example, seismic and well data have been used to link faults to historic subsidence and wetland loss near Lake Boudreaux.11

  • To improve earthquake risk assessment and mitigation in metropolitan Los Angeles, scientists have used seismic and well data from the oil and gas industry to map out previously unidentified faults. This work was motivated by the 1994 Northridge earthquake, which occurred on an unknown fault that was not visible at the Earth’s surface.12

More Resources

U.S. Geological Survey – National Geological and Geophysical Data Preservation Program.

References

1 U.S. Energy Information Administration (2016). Trends in U.S. Oil and Natural Gas Upstream Costs.
2 Bureau of Ocean Energy Management – Record of Decision, Atlantic OCS Region Geological and Geophysical Activities.
3 Varhaug, M. (2016). Basic Well Log Interpretation. The Defining Series, Oilfield Review.
4 Schlumberger – 1920s: The First Well Log.
5 AAPGWiki – Overview of Routine Core Analysis.
6 Zihlman, F.N. et al. (2000). Selected Data from Fourteen Wildcat Wells in the National Petroleum Reserve in Alaska. USGS Open-File Report 00-200. Core from the well “East Simpson 2”, Image no. 0462077.
7 Society of Petroleum Engineers PetroWiki – Petrophysics.
8 “Big Data Growth Continues in Seismic Surveys.” K. Boman, Rigzone, September 2, 2015.
9 U.S. Geological Survey Core Research Center – Frequently Asked Questions.
10 Kansas Geological Society & Library – Oil and Gas Well Data.
11 Akintomide, A.O. and Dawers, N.H. (2016). Structure of the Northern Margin of the Terrebonne Trough, Southeastern Louisiana: Implications for Salt Withdrawal and Miocene to Holocene Fault Activity. Geological Society of America Abstracts with Programs, 48(7), Paper No. 244-2.
12 Shaw, J. and Shearer, P. (1999). An Elusive Blind-Thrust Fault Beneath Metropolitan Los Angeles. Science, 283, 1516-1518.

Date updated: 2018-06-01
Petroleum and the Environment, Part 23/24
Written by E. Allison and B. Mandler for AGI, 2018

Optimizing pump reliability and performance

Optimizing pump reliability and performance

The offshore industry faces two main challenges: maximizing production within the limits of the reservoir, and minimizing operational costs while maintaining the safety of the platform. Pumps form one of the main groups of equipment that influence the outcome of both challenges and they require expert knowledge to ensure continued reliability and performance.

Murray Wilson, Sulzer UK argues that in each case, industry engineering expertise and commercial innovation are required to deliver these goals. Furthermore, the capital expenditure to improve reliability is most often far outweighed by the costs incurred by an unexpected failure and the subsequent costs of lost production. By taking a proactive approach and involving an expert maintenance provider, platform operators can deliver significant benefits to the business in the long term.

Improving performance

In the years following commissioning, the actual duty requirements of production pumps are likely to change – production rates may start to decline after the initial plateau period or the connection of additional wells may mean that potential production is being limited by the processing trains which were designed for lower volumes.

As equipment is pushed to operate significantly outside of its original design envelope, this can often cause operating problems which impact reliability and ultimately affect platform production. This also results in increased maintenance costs as operators and equipment specialists are required to overhaul plant more frequently.

Ultimately, the goal is to improve reliability and efficiency while reducing downtime and energy consumption, at the same time as satisfying API, ATEX, and many other engineering standards. However, this seemingly impossible task can be achieved through the implementation of preventative maintenance techniques and the adoption of the latest engineering designs for pumps.

Water injection pumps, seawater lift pumps, crude oil offloading pumps and fire suppression systems all require individual designs to deliver the best efficiency and productivity. At the same time, they also need specialist maintenance routines that will prolong reliability and effectiveness.

Proactive maintenance

A proactive maintenance regime is crucial to identifying potential issues before they develop into problems. However, this requires knowledgeable and experienced personnel to carry out the in-situ platform maintenance and these skills take time to perfect. The time required for this process can be greatly reduced by instigating a training program prepared by experts in equipment maintenance, who can pass on their collective knowledge in a structured and efficient manner.

In terms of through-life maintenance cost, preventative action is almost always less costly than corrective action, and adopting a carefully managed, proactive regime is crucial to identifying potential issues before they develop into problems. Two of the most prominent symptoms that occur prior to failure in mechanical and electrical equipment are increasing vibration and rising operational temperature.

Regular trending and analysis of radial and axial vibration signatures and thermographic/visual inspections of bearings, coils and electrical connections can prove invaluable. The latest developments in operational monitoring can be applied to existing assets and then used to determine the optimal point at which planned maintenance should be conducted.

Understanding cavitation

Most commonly seen on the pump impeller, cavitation is caused by a pressure difference, either on the pump body or the impeller. A sudden pressure drop in the fluid causes the liquid to flash to vapor when the local pressure falls below the saturation pressure for the fluid being pumped. Any vapor bubbles formed by the pressure drop are swept along the impeller vanes by the flow of the fluid. When the bubbles enter a region where the local pressure is greater than saturation pressure, the vapor bubbles abruptly collapse, creating a shockwave that, over time, can cause significant damage to the impeller vanes or pump housing.

In most cases, it is better to prevent cavitation rather than trying to reduce the effects on the pumping equipment. This is normally achieved by one of the three actions:

  • Increase the suction head

  • Lower the fluid temperature

  • Decrease the Net Positive Suction Head Required (NPSHR)

For situations where cavitation is unavoidable, or the pumping system suffers from internal recirculation or excessive turbulence, it may be necessary to review the pump design or minimize the potential for damage using a bespoke coating system.

Tackling erosion

The offshore production environment exposes pumps to harsh operating conditions and the abrasive nature of the fluids being pumped in certain processes on board can ultimately result in reduced efficiency and decreased pump performance.

Produced Water Re-injection pumps that are employed to force water back into the oil field and thus maintain the reservoir pressure needed to lift the oil to the surface are often subjected to high levels of abrasion. This is commonly the result of sand carryover from upstream filtration where there has been a process upset or where filtration systems are not adequate. Pumps that are used to transfer these fluids can experience significant levels of erosion, especially in areas with high flow velocities. The entrained sand particles act as an abrasive and higher working pressures only serve to compound the issue.

Pump manufacturers will aim to minimize flow velocities throughout the pump or design it in such a way that the flow velocities through close-running clearances are as low as practically possible within the duty for which the product has been designed. Under these circumstances, one of the most effective solutions is the use of specialist protective coatings, which can be used to protect selected areas in the pump.

Delivering the best coating system

With so many benefits arising from a specialist coating, it is important to determine the most appropriate materials, equipment and application procedures, otherwise the coating may degrade and fail prematurely. The processes and specifications used by companies such as Sulzer for applying coatings have been developed over many years and are essential to delivering a durable and reliable product.

To illustrate the importance of these procedures, especially in pump applications, consider the process of installing and removing an impeller. In many situations, the impeller is heated to allow it to be installed or removed from the drive shaft. This shrink-fit procedure can cause inappropriate coatings to be damaged during a routine maintenance operation. Sulzer has ensured that its coating technologies can withstand this thermal shock and continue to deliver long-lasting corrosion protection.

The importance of engineering expertise should not be underestimated and the benefits of engaging an experienced and well-resourced pump engineering company should not be overlooked. When dealing with complex engineering design, as seen in many pumping applications, it is very important to select to most effective and efficient resources to deliver a repair or refurbishment.

Meeting the logistical challenge

When it comes to complex equipment such as the large pumps encountered on offshore platforms, the most efficient delivery of maintenance will come from a provider of turnkey rotating equipment solutions. These organizations should have the necessary service facilities, trained & competent staff, logistical support and the service culture needed to support production critical plant.

In an ideal world, all the maintenance would be carefully planned and managed, but often it is necessary to respond to a situation immediately and deliver technical support, equipment, and materials at a moment’s notice. With a global network of service centers, capable of designing and manufacturing custom parts, Sulzer has not only the expertise but also the facilities and resources to meet the challenges faced by the offshore industry.

As a world-leading pump manufacturer, Sulzer offers state-of-the-art design and manufacturing facilities for oil and gas production, including subsea applications. This expertise is transferred throughout the company and used to support the maintenance and repair of any type of pumping asset.

 

Editorial contact: DMA Europa Ltd. : Philip Howe
Tel: +44 (0)1562 751436 Fax: +44 (0)1562 748315
Web: www.dmaeuropa.com
Email: [email protected]
Address: Europa Building, Arthur Drive, Hoo Farm Industrial Estate Kidderminster, Worcestershire, DY11 7RA, UK

Reader contact: Sulzer Turbo Services Houston Inc. :  Jennifer Cardillo, Marketing and Communications Manager, Americas Rotating Equipment Services
Tel: +1 713 567 2706 Fax:
Web: www.sulzer.com
Email: [email protected]sulzer.com
Address: Sulzer Turbo Services Houston Inc. 11518 Old La Porte Road La Porte, TX 77571 USA

 

About Sulzer:Sulzer is the leading worldwide, independent service provider for the repair and maintenance of rotating machines including turbomachinery, pumps and electro-mechanical equipment. With a global network of over 180 technically advanced manufacturing and test facilities, Sulzer offers a collaborative advantage that delivers high-quality, cost-effective, customized and turnkey solutions, providing its customers with the peace of mind to focus on their core operations.

Sulzer Rotating Equipment Services, a division of Sulzer, can accommodate all brands of rotating equipment including turbines, compressors, generators, motors, and pumps. With an enviable track record, dedicated teams of on-site engineers provide best-in-class solutions to ensure that the most effective service is delivered.

Sulzer is dedicated to providing superior service solutions to a range of industries including power generation, oil and gas, hydrocarbon and chemical processing, water, and air separation. Every solution is customized to suit the business needs of each application – whenever or wherever that may be.

With a long history of providing engineering service support, Sulzer is headquartered in Winterthur, Switzerland where it began in 1834. Today, with sales over US$ 3 billion and with approximately 14,000 employees, the Sulzer footprint spans across the globe. The core aim is to deliver a flexible and cost-effective service that optimizes customer operational efficiency and minimizes downtime.

For more information on Sulzer, visit www.sulzer.com

The image(s) distributed with this press release may only be used to accompany this copy, and are subject to copyright. Please contact DMA Europa if you wish to license the image for further use.

Visit the DMA Europa website for the full text in PDF format and the associated high-resolution image and video files: Website

BP deploys Plant Operations Advisor on Gulf of Mexico platforms

Advanced analytics solution, developed with BHGE, will be installed on BP’s upstream assets around the world

HOUSTON – BP announced today that it has successfully deployed Plant Operations Advisor (POA), a cloud-based advanced analytics solution developed with Baker Hughes, a GE company, across all four of its operated production platforms in the deepwater Gulf of Mexico.

The announcement comes after an initial deployment of POA proved the technology could help prevent unplanned downtime at BP’s Atlantis platform in the Gulf.

The technology has now been successfully installed and tested at BP’s Thunder Horse, Na Kika, and Mad Dog platforms – and it will continue to be deployed to more than 30 of BP’s upstream assets across the globe.

Diana and Barth keep a close eye on the plant

“BP has been one of the pioneers in digital technology in our industry, and co-development of Plant Operations Advisor with BHGE is a key plank of modernizing and transforming our upstream operations,” said Ahmed Hashmi, BP’s global head of upstream technology. “We expect the deployment of this technology not only to deliver improvements in safety, reliability, and performance of our assets but also to help raise the bar for the entire oil and gas industry.”

Built on GE’s Predix platform, POA applies analytics to real-time data from the production system and provides system-level insights to engineers so operational issues on processes and equipment can be addressed before they become significant. POA helps engineers manage the performance of BP’s offshore assets by further ensuring that assets operate within safe operating limits to reduce unplanned downtime.

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“BP has been one of the pioneers in digital technology in our industry, and co-development of Plant Operations Advisor with BHGE is a key plank of modernizing and transforming our upstream operations.”

Ahmed Hashmi, BP’s global head of upstream technology

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Now live across the Gulf of Mexico, POA works across more than 1,200 mission-critical pieces of equipment, analyzing more than 155 million data points per day and delivering insights on performance and maintenance. There are plans to continue augmenting the analytical capabilities in the system as POA is expanded to BP’s upstream assets around the globe.

BP and BHGE announced a partnership in 2016 to develop POA, an industry-wide solution for improved plant reliability. The teams have built a suite of cloud-based Industrial ‘internet of things’ (IoT) solutions that have been tailor-fit for BP’s oil and gas operations.

“The partnership between BP and BHGE has resulted in a unique set of capabilities that quickly find valuable insights in streams of operational data,” said Matthias Heilmann, president, and CEO of Digital Solutions and chief digital officer for Baker Hughes, a GE company. “Together, we are creating leading-edge technologies to automate processes and increase the safety and reliability of BP’s upstream assets. As we extend the solution globally, this will become the largest upstream Industrial IoT deployment in the world when complete.”

BP is currently in the process of deploying POA to its operations in Angola with additional deployments in Oman and the North Sea scheduled for 2019.

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About BP

BP is a global producer of oil and gas with operations in over 70 countries. BP has a larger economic footprint in the U.S. than in any other nation, and it has invested more than $100 billion here since 2005. BP employs about 14,000 people across the U.S. and supports more than 106,000 additional jobs through all its business activities. For more information on BP in America, visit www.bp.com/us.

About Baker Hughes, a GE company

Baker Hughes, a GE company (NYSE: BHGE) is the world’s first and only full stream provider of integrated oilfield products, services, and digital solutions. We deploy minds and machines to enhance customer productivity, safety, and environmental stewardship while minimizing costs and risks at every step of the energy value chain. With operations in over 120 countries, we infuse over a century of experience with the spirit of a startup – inventing smarter ways to bring energy to the world.

Further Information

Name: BP U.S. Media Affairs
Email: [email protected]

Name: Ashley Nelson
Phone: +1 925 316-9197
Email: [email protected]

Name: Gavin Roberts
Phone: +44 7775547365
Email: [email protected]

Petroleum Institute announces ‘Explore Offshore’ coalition

TALLAHASSEE — Proponents of drilling for oil and natural gas haven’t given up on tapping areas closer to Florida’s shoreline despite repeated assurances those waters will be exempt from a White House plan to expand exploration.

The Washington, D.C.-based American Petroleum Institute announced Wednesday a multi-state “Explore Offshore” coalition to support the Trump administration’s plan to open previously protected parts of the Atlantic Ocean and the eastern Gulf of Mexico to oil and gas drilling.

The coalition’s Florida team, which is focused on the eastern Gulf waters, includes former Lt. Gov. Jeff Kottkamp, former Okaloosa County Commissioner Wayne Harris, former Puerto Rico state Sen. Miriam Ramirez and Florida Petroleum Council Executive Director David Mica.

Mica said Floridians use more than 25 million gallons of motor fuel a day, while the industry is restricted from “some very, very good areas” that potentially have oil.

We need to do it in an environmentally responsible manner, but we must go forward,” Mica said. “I think that it’s really putting your head in the sand if you think that we’re not going to need a lot more oil and gas into the future and that we can rely only on alternative fuels.”

Many Florida officials, including Gov. Rick Scott, Department of Environmental Protection Secretary Noah Valenstein and members of Florida’s congressional delegation from both sides of the political aisle have denounced the possibility of opening to drilling almost all of the nation’s outer continental shelf — a jurisdictional term describing submerged lands 10.36 statutory miles off Florida’s west coast and 3 nautical miles off the east coast.

Interior Secretary Ryan Zinke appeared briefly Jan. 9 in Tallahassee to announce drilling would not occur off the Florida coast. But the Trump administration’s stance has not been formalized and continues to draw questions.

U.S. Sen. Bill Nelson, D-Fla., on Wednesday equated the petroleum industry’s new coalition with lingering skepticism over Zinke’s assurances that waters off the Florida coast will be exempt from the plan.

“Here we go. Like us, Big Oil doesn’t believe Florida is really ‘off the table’ to new drilling — despite what Scott and the Trump Administration keep saying — and now they are making a new push to drill closer to Florida’s shores,” Nelson tweeted. “We can’t let that happen!”

The federal Bureau of Ocean Energy Management is expected to release a draft report on the offshore proposal before the end of the year. That will kick off the second round of public hearings.

Drilling proponents have hailed the prospects of exploring for oil and gas closer to shore as benefiting consumers by potentially creating jobs and additional government revenue while strengthening national security.

The American Petroleum Institute said its coalition features more than 100 businesses, organizations and officials from Virginia, North Carolina, South Carolina, Georgia and Florida.

In its release, the institute highlighted Florida’s dependence on natural gas, which generates 67 percent of the state’s electricity, and forecast that offshore development could result in $2.6 billion in private investment in Florida and $1 billion per year in state revenues.

Kottkamp said the “availability of affordable energy is critical” to Florida’s quality of life.

“We look forward to working with our local leaders to discuss ways to maintain our state’s natural beauty while at the same time expanding opportunities to keep our nation energy independent,” Kottkamp said in a statement.

In November, Florida voters will decide whether to approve a proposed constitutional amendment that would ban nearshore oil and gas drilling. That ban would affect state-controlled waters.

Source: Panama City News Herald

OFFSHORE DECOMMISSIONING IN ASIA PACIFIC REGION: WHY ‘RIG TO REEF’ IS VITAL

The Asia Pacific region is set to follow the North Sea in increasing its decommissioning activity over the next decade. Indonesia, Brunei, Malaysia and the rest of the region is home to 833 installations that are on or over 20 years old – the average life expectancy of offshore assets. But with so much of the region’s infrastructure under threat from decommissioning, many have questioned the impact to the environment.

A thought piece by the National University of Singapore (NUS) singled out the importance of rig to reef in this context back in 2012. In this blog, we explore what could be done in the region to both keep the integrity of the sea bed and complete decommissioning applications as efficiently as possible.

RIG-TO-REEF

Rig-to-reef (RTR) is the practice of converting decommissioned platform infrastructure into artificial reefs for the seabed. The practice has already proved popular in the Asia Pacific when the storm-damaged Baram-8 in Malaysia was made into an artificial reef. Despite there being no current RTRs in place in the region, there is sure to be an appetite as decommissioning work increases.

Rigs prove popular with sea life, especially as they become an integral part of the seabed over their 20-30 year life span. An OCS report that focussed on the Gulf of Mexico in 2000 stated that fish densities were 20-50 times higher around the platforms than anywhere else in open water – a true sign that artificial reefs work.

PROS OUTWEIGH THE CONS

While operators may look towards asset life extension techniques to keep relevant rigs operating, those who are set to decommission will be pleased to know that the pros outweigh the cons in terms of implementing RTRs with old assets.

Despite potential navigational issues around the Asia Pacific region, operators creating RTRs could benefit from being more environmentally friendly, increasing fisheries in the field, and potentially negating costs such as rig disposal. The question on whether RTRs would be welcome in the region are so far undecided and confusing by governing bodies, according to the NUS.

GIVEN THE GREEN LIGHT

In her presentation for the National University of Singapore, Youna Lyons highlighted the large discrepancy between governing bodies and law in the Asia Pacific region that meant operators looking to RTRs would be left confused as to whether they could undertake a project after decommissioning.

“(While) international law does not prevent the re-use of rigs as artificial reefs, provided that it does not compromise the safety of navigation, IMO guidelines (on the matter) are inadequate. A paradigm shift is needed in the approach.”

The biggest issue seems to be the safety of navigation around such artificial reefs by shipping traffic. That aside, the law states that rigs can be re-used, it is just a case of where they will be able to be positioned.

RIG TO REEF IS VITAL

In summary, the presentation reveals how vital rig to reefs can be for both operators and environment. While operators can potentially save money, and enhance the environment they’ve extracted from, the seabed and sea life can see drastic increases in activity if the manmade reefs are positioned well – as long as governing bodies and local authorities agree, Asia Pacific could benefit from more RTRs in the future.

THE INCREASE OF DECOMMISSIONING

As operators around the world review their aged assets, in the current climate it is no surprise to see decommissioning projects beginning on non-profitable rigs. In the Claxton Engineering Decommissioning Case Study Pack, you will learn how the Claxton team have already helped operators on their decommissioning projects and helped to save time and money too.

To find out more about the free offshore Decommissioning Case Study Pack, and to get your hands on a copy, click here.

Please be sure to follow and subscribe to Claxton at http://insights.claxtonengineering.com/.

Originally written and posted by Andy Norman, Head of Brand and Marketing, Claxton.

 

Video

Johan Sverdrup – the digital flagship

Digital technologies are shaping the world around us, and Statoil intends to be a driver of change in the energy industry. This film provides an overview of the digital ambitions and technologies which Statoil is working to implement on the Johan Sverdrup field to further improve safety, production and value.

Published on Feb 8, 2018

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