Tony Duncan considers smaller, simpler and more cost-effective options for age old industry problems
The oil and gas business has, is, and will probably continue to be, conservative in its approach to engineering. If it develops a product or system that works on one project, its variant will likely be used again on the next project and so on, project after project. Operators tend to repeat what has been done before, because it is tried and tested.
For example, the development of floating production storage and offloading (FPSO) vessels found their original use in the UK North Sea. Since then, they have been adopted and adapted globally and the system designers have incrementally modified the designs, because of increases in top tension, water depth, environmental conditions and so on. However, these developments have driven the technology towards a trend of making everything larger, more complicated and more expensive. The flexible pipes used have become more complex, the vessels utilised to install the FPSOs have become larger, the buoy systems used to support the riser system have been made bigger, and the result is a FPSO that has a large turret or porch system that can, in some cases, break project economics or introduce a too high a level of project risk.
Engineers in oil companies, design houses and engineering, procurement, construction and installation (EPCI) contractors, use past project experience when they look to a new project or tender. Take, for example, a mid-water arch, commonly used for supporting risers. When engineers start a new project, what is the first thing they look to? Past examples of mid-water arch design or design bases are a natural starting point. Then, they add in the new conditions such as water depths, environmental load, sour service and CO2 requirements, temperature, etc. Factoring in these new conditions often adds in more complexity, more weight and more risk, all without challenging why a mid-water arch is being used in the first place. Some of the early mid-water arches used in the UK sector weighed about 150 t. Offshore Brazil, projects such as Guará-Lula use a form of the mid-water arch that weighs in excess of 2000 t. The spiral is in train: larger projects mean more and larger installation vessels, and more commercial and technical risk.
The full article is available to download here: Simpler_Options_For_Oil_Industry_Problems
This article appeared in the December 2018 issue of Oilfield Technology.
Understanding corrosion of flexible pipes at subsea oil and gas wells
“Flexible pipes installed at two offshore natural gas wells in Brazil’s pre-salt fields recently ruptured after only a few years of operation. These pipes were expected to last more than 20 years, so Petrobras, the company developing the fields, investigated the cause of the failure. They discovered damage to the pipes’ outer cover and found corroded steel armor wires in the pipes. Executives were surprised to learn that high concentrations of carbon dioxide contributed to the corrosion and eventual ruptured pipes. Failures, while infrequent relative to the thousands of flexible pipes in operation, have also occurred in at least four flexible risers connecting floating production vessels to subsea wells off the coasts of Norway and Africa.
When flexible pipes were first introduced 30 years ago, it was thought that the interior of the pipes remained dry and noncorrosive. However, engineers now know that the unique environment that traps water vapor and carbon dioxide between layers of steel inside the pipe contributes to corrosion—even when its external cover is undamaged. Producers are beginning to use corrosion-resistant composite flexible pipes for subsea flow lines at deep wells. Companies are also testing and developing hybrid systems that combine steel and composite pipes to maximize the benefits of both systems.
With oil and gas reserves in shallow waters running dry, producers are turning to fields in deep and ultra-deep waters off the coasts of Brazil, Norway, Angola, and the United States. Bringing fluids through 3000 meters of water to the surface poses new challenges for well operators: production fluids with increased temperatures and pressures that challenge welds; increased carbon dioxide—and sometimes hydrogen sulfide—that scour and weaken steel; deep ocean water pushing on pipes with increased pressures; and currents trying to drag pipes through the water.
However, there is a way to eliminate stress-induced corrosion cracking: Eliminate the steel from flexible pipes. Companies such as Magma produce flexible pipes for the oil and gas industry by winding layers of composite reinforced with glass or carbon fibers around a polymer liner. Each layer of the thermoplastic composite is fused to the one below it. Composite pipes are much lighter than steel flexible pipes, so operators can use simpler, less expensive equipment to install them.”
The full article is available to download here: Understanding_Corrosion_Of_Flexible_Pipes_At_Subsea_Oil_And_Gas_Wells.
Extract from MRS Bulletin, 43(9), 654-655. Understanding corrosion of flexible pipes at subsea oil and gas wells. Author Fellet, M., & Nyborg, R. (2018). doi:10.1557/mrs.2018.214
Does light weight carbon fibre pipe spell the end for big expensive and environmentally unfriendly offshore vessels?
Based in Portsmouth, Magma Global set out with the vision to build the world’s most technologically advanced pipe for use in subsea oil and gas production. Their rationale was based on the conviction that light weight carbon fibre composite pipe could revolutionise subsea and deepwater oil and gas production by fundamentally changing both its economics and environmental impact. After seven years of pipe development and qualification is the dream coming true?
Tullow Oil is an independent producer who views technology as a way of significantly reducing cost and risk. For its TEN project in Ghana Tullow has awarded Magma Global with two 2.5km m-pipe flowlines. The 6 inch spoolable carbon composite m-pipe flowlines will be deployed from a 10m diameter reel, with the total weight of pipe and deployment package only 100 tons. This compares with over 500 tons for the equivalent steel flexible pipe product normally used in the industry.
This very significant saving in weight means both of the new flowlines can be deployed from the MPCV, a 4,800 ton vessel of which there are many around the world, as opposed to the 14,000 ton specialist lay ship which would normally be required.
“Being able to use a small vessel has allowed us to effectively manage and reduce costs.”
“Reducing the operational costs through the adoption of proven new technologies is great example of the impact we can have by selecting the right pipe and deployment system for developments.”
Aside from the cost benefits, the pipe’s light weight means shipping costs are reduced and handling is much easier. Being a carbon fibre composite, m-pipe is also much stronger and, most importantly, does not rust in seawater or corrode with exposure to H2S, CO2 or some of the more aggressive chemicals involved in oil and gas production.
Martin Jones, Founder and CEO of Magma commented, “Our goal is eventually to replace metallic pipes for subsea oil and gas production in all applications, but we recognise it’s a long road in an industry which is naturally cautious with any new technologies responsible for transporting oil under water.”
“That said, a number of operators are recognising the benefits Magma’s approach and m-pipe technology can bring, not just in cost savings but in a more environmentally friendly approach that is intrinsically safer. As a result, we are seeing a significant acceleration in adoption by clients around the world in a wide range of subsea applications.”
The total annual cost of steel corrosion is $2,500 billion across the globe: 3% of GDP
Steel corrosion review by Geoff Small, Victrex Market Technology Manager
Sulfate-reducing bacteria (SRB) are among the oldest forms of life, having contributed to the sulfur cycle which started around 3.5 billion years ago. There are over 220 species of SRBs and they occur naturally in most anaerobic environments, contribuing to the degradation of organic matter.
Although many bacteria also reduce sulphates in small quantities, sulphur reducing bacteria reduce sulphates in significantly larger amounts. Toxic hydrogen sulfide is a waste product of SRBs, with its rotten egg odor a marker for the presence of sulfate-reducing bacteria in nature, such as the sulfurous odors of salt marshes and mud flats. SRB occur naturally in sour crude oil and seawater and can anaerobically oxidise methane to form sulphide ions, deriving their energy from oxidizing organic compounds or molecular hydrogen.
The subsea SRB challenge
Apart from localized corrosion risk, protecting any steel structures from SRBs costs the oil and gas industry heavily in chemical treatments such as corrosion inhibitors, biocides and scale inhibitors for carbon steel and pipelines.
“The total annual cost of corrosion is estimated to be $2,500 billion across the globe, representing over 3% of global GDP. Within oil and gas 57% is related to a combination of pipe costs and direct capital expenditure related to directly combatting the effects of corrosion.”
A big challenge in oil and gas is that the hydrogen sulfide SRBs produce reacts with any metal ions in seawater to produce metal sulphides which are insoluble and often black or brown, such as ferrous sulfide (FeS).
Sulfate-reducing bacteria create problems when any metal structures are exposed to sulfate-containing water. The interaction of SRBs at the interface between the metal and creates a layer of molecular hydrogen on the metal surface. Sulfate-reducing bacteria then oxidize the hydrogen and create hydrogen sulfide, which is a significant corrosion problem for any subsea pipe or structure.
When dissolved, hydrogen sulphide forms a weak acid which is corrosive and with steel forms a scale layer of iron sulphide.
Depending upon the operating temperature this scale may be passive or can accelerate galvanic corrosion by acting as an anode.
The additional challenge of the presence of CO2 exacerbates what is already a subsea corrosion risk.
“Both general and localized pitting corrosion rates of carbon steel were found to nearly double in solutions containing 10v% CO2 and 10 v% SRB compared to solutions containing either CO2 or SRB alone”. NACE report
SRB are known for causing anaerobic corrosion of buried pipelines where iron sulphide is formed and accumulated on the surface of steel pipelines, which then accelerates the further dissolution of iron.
SRB bacteria accumulation can lead to pitting of steel and the increased corrosiveness of water, raising the possibility of hydrogen blistering or sulphide stress cracking.
The PEEK solution
In applications where Victrex PEEK polymer is used in Thermoplastic Composite Pipe (TCP) such as Magma’s m-pipe®, it has a smooth surface which ensures a high resistance to the build-up of any bacteria or other organic matter. As PEEK polymer is highly chemically resistant, it is extremely difficult for SRB to be able to gain a foothold on the surface of the PEEK bore in a pipeline. But PEEK’s benefits don’t stop there. Where SRB bacteria are present then PEEK polymer also exhibits an excellent resistance to high concentrations of H2S and, unlike steel pipe, PEEK s not affected by corrosion, scale formation or hydrogen induced embrittlement.
Victrex has generated a significant data set around PEEK resistance to hydrogen sulphide following International Standards such as NORSOK M710 and ISO 23936. In addition Victrex has exposed PEEK polymer to ageing at various temperatures in a three phase environment where the gas phase is 100% H2S. At temperatures below 175°C there is no effect of this gas on the polymer and only at higher temperatures (>200°C) does a gradual decrease in performance (through chain scission) begin to occur.
Left is a graph plot of tensile strength of Victrex PEEK polymer versus ageing time in the pure H2S phase of a three phase aromatic NORSOK M710 type environment at 125°C and 175°C. This data demonstrates the exceptional sour gas resistance of this polymer.
The smooth surface of products like Magma m-pipe® which utilise Victrex PEEK provide inherent chemical resistance, especially to sour gases, which means that there is now a viable alternative to carbon steel pipe for subsea use that eliminates the expensive costs of corrosion inhibitors, biocides and scale inhibitors.
The role of composite pipe as part of a cost saving drive to bring the UKCS back to profitability
Subsea production might have been born in the Gulf of Mexico (GoM) and Brazil before the 1980s, but it was in the UK North Sea sector that it grew from infancy to maturity.
The British sector has not been short of ambition, adventure, enthusiasm and risk-taking, and the North Sea was where it was at as far as subsea technology went, at least until the expansion into West Africa since 2000. This began with the Shell/Esso Underwater Manifold Centre and carried on with shallow-water projects by Amerada Hess, then by BP west of the Shetlands beyond 400 m (1,312 ft) and Chevron’s recent Alder HPHT 28-km (17-mile) subsea tieback. Scroll forward to the present, and what is found today is a British offshore sector in a major funk.
- Total expenditure on the UKCS decreased from £26.6bn in 2014 to £19bn in 2016
- UKCS capital investment fell to £9bn in 2016 from a record £14.8bn in 2014
- The UKCS generated a free cash-flow deficit of £2.7bn in 2016 (Oil & Gas UK)
- Average rate of return for extraction companies on capital investment in Q1 2016 was just 0.2% vs 50% in Q1 2011
The oil price crash of late 2014 has had much to do with UKCS woes, but there are other significant factors as well. The North Sea sector has long been known as a high cost location, both for capex and opex, with years of underinvestment in exploration by majors hunting elsewhere in the world, leaving the sector with a portfolio of around 350 minifields that will require clever thinking to develop.
The price crash finally focused everyone’s attention on what was needed: a sector- wide analysis undertaken by Sir Ian Wood in 2013 and presented in February 2014. This review added a new phrase to the offshore lexicon – ‘maximum economic recovery’- and sent the UK down a path it had never been before, trying to save the offshore sector.
In parallel with this localised approach, there had been an urgent industry drive to reduce costs. This was a process that had actually begun before the crash, going back to the early part of 2013 with operators already applying the brakes to big deepwater projects.
For example, BP’s original scheme for Mad Dog 2 expansion in the GoM put forward in 2013 had a price tag of $20 billion. No way, said management, go back and look again. So it did, and the development scheme, described as more standardized, was sanctioned at the beginning of December last year with a price tag of $9 billion.
BP would like to take most of the credit for this major capex reduction, which it said is due to a less expensive semisubmersible floating production system, and it certainly deserves some plaudits. However, it also had the opportunity to re-tender the whole project at a time when there was a dearth of big projects going ahead, and could have benefited from general cost reduction in equipment and services across the industry.
Wood report recommendations and studies
Harte Energy has looked back at the Wood report to see which recommendations have come to fruition. One of these was the creation of a new industry regulator and some at the time expressed wonderment at how a new regulatory body could make a difference to the future of the sector. However, the recent work the Oil & Gas Authority (OGA) has undertaken has already proved many critics wrong already.
If the future of the UK sector is to be based on the portfolio of marginal fields (those with less than 50 MMboe in reserves), a significant majority, about 200, will be developed as tiebacks to existing infrastructure. Many, and possibly most, will also be developed using subsea wells.
The OGA already has taken on board the need to ensure that the right technology is available to all operators. In what must have been an unprecedented action by a UK regulator, it commissioned four studies to determine the economic viability of fields that might make use of specific technology and what the impact might be. There seems to have been some collaboration between OGA and Oil & Gas UK’s Efficiency Task Force, the latter body which is an association of operators and main contractors.
Two studies involved looking at conventional subsea tiebacks and making use of already proven but less expensive pipeline tie-in technology, which produced savings of 18% to 28% on project capex. Some of the technologies identified as applicable in such cases are mechanical rather than welded hot taps, mechanical connectors as an alternative to welded pipe and spooled pipelines and composite pipe such as m-pipe® offered by Magma Global.
Other studies also looked at riser systems for FPSO units and a different configuration of pipeline bundles with integral manifolds, where savings of 15% to 25% are suggested.
OGA has also looked at and identified other technologies that might be applicable for low-cost standalone developments, which represent nearly one-third (120) of the marginal fields. Some of the options include:
- Mini-FPSO units
- Unmanned production buoys
- Subsea storage to eliminate long pipeline tiebacks
- Subsea factories with seabed processing prior to export
The challenge of cluster development
OGA has also analysed the marginal field portfolio and developed a strategy based on field location, and proximity to infrastructure and to other finds. It also has looked at some specific clusters to see how they might be developed. Already analysed is the West Sole Catchment Area in the UK’s Southern North Sea Gas Basin, with combined proven reserves of at least 14 Bcm (500 Bcf). This cluster includes Centrica’s Olympus discovery, Dana Petroleum’s Platypus find, two small Premier fields and one held by Hansa Petroleum plus one relinquished find (Glein West) and at least six other prospects.
One challenge that often has reared its head in the sector is alignment of development priorities. This cluster, for example, has four operators and 11 licensees, some of them small. Trying to get this group to agree to a development scenario, timetable and program is not an easy task. One advantage that OGA has is control of licenses. To make this cluster more economic, it could throw the relinquished find into the mix to benefit the entire development.
The impact of the UK Oil & Gas Technology Centre
Bolstering OGA’s enterprise was the formal launch in February of the Oil & Gas Technology Centre (OGTC) in the U.K. One of its first tasks is its ‘small pools’ initiative, which is running parallel to the work on marginal fields. Even before the launch OGTC’s team had thrown down the gauntlet by declaring that it is aiming to eliminate stranded assets by 2025, a rather bold declaration.
Two of the technologies that are at the top of its wish list involve gas handling and umbilical-less subsea systems. Disposal of associated gas that comes with small oil finds has often in the past been a major roadblock to development as the options are either environmentally or economically unpalatable. This includes flaring in the case of an FPSO unit or small platform or drilling a gas disposal well as part of a subsea development.
As for eliminating the umbilical from the subsea system, this has been a desire for decades, but throughwater communications has a number of limitations that to date have not been overcome. It has even been suggested that technology developed for the military could be made available, such as that used with permanently deployed sensors on the seabed to track submarines, but this is a challenge that will test the mettle of both engineers and regulators.
New Technology has a clear part to play in any new subsea developments, helping to reduce Capex required in tie-backs and their subsea deployment.
Whether the oil and gas industry has the mettle or bravery to grasp qualified and proven new technologies like thermoplastic composite pipe to reduce Capex and Opex in the short term remains to be seen. But, along with other new technologies, composite pipe could become a key part of the hope and future of the UK’s North Sea in the next decade, reducing whole-life maintenance costs due to better performance against sour fluids and corrosion and delivering increased subsea longevity.
This blog is based on an article first published in EPmag.com in April 2017. To read more click here
The benefits of composite materials for the oil and gas industry
Magma CEO Martin Jones talks about carbon composite use in oil and gas and major industries.
“Composite materials provide a solution to common oil and gas industry challenges such as corrosion, fatigue and weight, all of which contribute to increased risk and cost to offshore projects.
Once oil and gas reserves in deeper water come into the picture, the challenges become even greater, with much larger subsea components that are often required to work under much higher pressures, sour service and higher temperature conditions.
Reliability as well as cost becomes paramount. There is good news, composite technology applications have already been matured in other industries, which is to the benefit of the oil and gas industry.
Composites in aerospace
Most significantly for the oil and gas industry, composite technology has matured particularly well in the heavily regulated aerospace industry, a very safety critical industry sector. Almost every single commercial passenger aircraft that you step on today stays in the air as a result of structural composites. The Boeing 787 is 70% composite, for example, with a carbon fibre composite fuselage, wings and tail. The wing spars of the Airbus A320 and 380, 340 and 350 all have composite wings, as well as tail and fuselage components.
The passenger aircraft industry has spent the last 30 years working on composite materials science and analysis tools to predict strength and flight performance. The benefits of this work is now transferring into a wide range of other cost and risk conscious industries.
The primary drive for the aircraft industry is operating economics as the key concern is aircraft weight, in order to safely maximise the number of passengers that can be carried and to reduce fuel bills. Composites not only give you the strength and fatigue capability that is essential for the airframe, but also a long life that maximises the return for those airlines that buy composite aircraft.
Composites in civil engineering
The other key industry adopting composites is civil engineering, where weight is not so much of an issue, like in the oil and gas industry which has not been concerned as much about weight historically, although this is changing. In civil engineering the drivers are different, but just as important.
Whilst weight is indeed an issue in certain structures, like bridges, it’s fatigue performance and reliability that are the key drivers for the increasing use of carbon fibre composites in bridges and large architectural structures.
The two biggest composite projects in the world today are civil engineering projects, one is the new bridging system and tower cladding in Mecca Saudi Arabia, which is the largest use of carbon fibre in any project, and the second is the West Gate Bridge in Australia.
As an aside, the third largest global project using carbon fibre are the Sailing yacht A masts build by our subsidiary company Magma Structures and delivered in mid-2015.
Growth and maturity in the use of composites
This has come about due to three key factors. Firstly, the general improvement in composite materials now available, such as the T700 industrial grade carbon fibre and PEEK used in Magma’s m-pipe®. These materials are fully qualified and have also been used extensively in aerospace, and the Victrex PEEK Magma uses is qualified in a number of oil and gas applications in addition to its extensive use in aerospace.
The second area is automated manufacturing technology. The aerospace industry has really pioneered the use of robots to build composite structures, mainly for two reasons.
Firstly, they needed reliability and consistency to give them the quality they required. Secondly, they needed the cost reduction that comes by taking people out of manufacturing processes, exactly the same sort of drivers that we have in our m-pipe® manufacturing process.
In truth, whilst the m-pipe® manufacturing line runs 24 hours a day with two people per shift monitoring production, the reality is that it is completely automated and so really runs operated by just one person, with the second person purely as back-up.
Thirdly, there has been a steady maturing of the analysis tools behind composite materials, and that’s just as critical for oil and gas as it is for aerospace.
Magma m-pipe® – capitalising on composite materials and manufacturing
Magma m-pipe® is a high performance carbon fibre, Victrex PEEK and S-2 glass thermoplastic composite pipe. Toray, who supply Magma for m-pipe®, is the world’s largest carbon fibre supplier. They provide most of the carbon fibre for Airbus and Boeing for their major airframe structures.
We also use Victrex PEEK, a material already used extensively in the oil and gas industry with hydrocarbons.
So materials selection has been key to Magma and we will continue to use these materials to enable us to qualify m-pipe® fully.
From a production perspective, what is interesting is that just ten years ago Magma’s m-pipe® simply couldn’t exist. Whilst the high quality raw materials were available, the manufacturing technology wasn’t there in terms of its sophistication, reliability and, ultimately, commercial sense. For example, m-pipe® manufacture requires very high power lasers that weren’t available even five years ago.
So, today, we have increasing demand from the oil and sas industry as it faces significant technical challenges and even greater commercial challenges, combined with a rapidly maturing technology which has the ability to transform the cost effectiveness of subsea development and operation.
In the last 18 months we have seen the industry take significant steps towards the adoption of this inevitable technology with the publication of DNV GL F119 Recommended Practice for Thermoplastic Composite Pipe, released in December 2015.
Significant investment in project specific qualification and testing has also been combined with increasingly ambitious field deployments. With the challenge on costs in the current oil price environment, combined with the increasing technical challenges, the rapid maturing and adoption of composite pipe technology within the sector is an essential element in the industries’ strategic response.
- To see the video of Martin Jones’ introduction to composite technology for oil and gas – click here
Magma Integrated deployment package (IDP) for efficient light well intervention.
The offshore market recognises that hydraulic pumping light well intervention (LWI) has the potential to significantly increase the productivity of many subsea wells, from high pressure injection of chemicals through to scale squeeze and formation fracking, designed to stimulate higher rates of productivity from reservoir formations.
The hydraulic light well intervention opportunity
70% of all operational subsea wells are now in excess of 5 years old and productivity is decreasing. With global demand for oil and gas still increasing, production costs rising and oil prices still depressed, light well intervention activities are naturally growing, as they allow higher oil production with minimised CAPEX. Light well intervention costs are also significantly less than new field costs, with the cost per barrel from intervention around one tenth the production cost from new fields, hence the steady recent growth of light well intervention.
Average recovery without regular intervention is only 22% of available oil (Offshore Network report 2015). Based on the remaining 78% of global hydrocarbon reserves in subsea assets that could be recovered through intervention, just a 1% increase in recovery would be equal to 90 Billion BPD or the equivalent of 3 years of full global production at current levels.
Why isn’t more light well intervention activity happening?
Within the light well intervention market, hydraulic LWI market is still currently small and developing, but with significant potential. Whilst there is evidence that light well hydraulic pumping activities are already being contracted by some operators, the intensity of such activities is significantly lower than the industry might expect. The fact is that many people are talking about it, but few are doing it, for a whole range of different reasons, and many of which are also related to the limitations and risks of existing pipe technology.
One of the biggest challenges is the number of subsea wells now operating in deeper water, where rig availability is more limited and their rates are higher than vessel costs for intervention work. This is another key reasons that the offshore industry does not already have a larger and more active sector focused on delivering efficient hydraulic light well intervention, as it has traditionally had reservations about the capabilities and risks of using smaller but cheaper and more readily available vessels for well intervention work.
The challenges of existing hydraulic LWI technology
For intervention the industry has successfully employed coiled tube and, to a lesser extent, non bonded flexible and jointed steel pipe for chemical injection operations. When such operations have been undertaken in shallower water under 300m (1,000ft), this has been relatively successful, as the pipe products are relatively cheap and intervention operations only require low intervention fluid pressures and medium-level flow rates.
However, as depths, pressures, flow rates and the nature of the intervention fluids becomes increasingly challenging, existing coiled tube, steel and non bonded pipes reach the very limits of their design capabilities and other challenges that come from their relatively short life span. From conversations with large intervention contractors, Magma understands that the pipe factor is the key reason that they have been reticent to offer deep water fluid pumping services. This means that valuable intervention work is either avoided, missing potential production upsides, or conducted using a more expensive and complex MODU and full workover package.
Coiled tube, drill pipe and non bonded flexible pipe have well-known issues that impact intervention service efficiency, pipe life and that limit their scope of application and the future successful expansion of the hydraulic stimulation market. There are many common challenges with existing pipe that include fatigue sensitivity, complexity of pipe management for vessel deployment, limited corrosion resistance, high relative deployment weight, limited diameter and pressure capability, limited intervention fluid flow rates and pipe longevity, longevity and associated replacement cost and the need for regular operational re-spooling.
The Magma m-pipe® riser and IDP delivery system solution
The Magma intervention strategy has been to focus on the two key elements – a downline pipe specifically designed for deep water intervention, and an integrated compact back-deck vessel deployment system. This combination is developed with the objective of maximising the technical feasibility of hydraulic LWI operations, to accelerate the growth of this important market and to deliver against the immediate potential of maximising production and minimising cost and risk.
Magma m-pipe® is a light, strong and flexible carbon fibre fluid delivery pipe, and the key component that delivers the high pressure intervention chemicals to the wellhead. In reality m-pipe® is a dynamic deep water riser system that delivers against all of the design and operational complexities that deep water, high pressure and high flow rate hydraulic intervention systems require.
m-pipe® addresses the limitations of existing LWI pipe and is a high performance subsea riser pipe:
- Light weight, fatigue resistant carbon composite riser pipe
- High strength and capability of long-term operation at up to 15ksi fluid pressures
- Capable of handling highly aggressive intervention fluids like HCl and hydrofluoric
- Substantial increase in flow rates versus existing coiled tube systems
- Spoolable delivery system with up to 3,000m (10,000ft) of riser pipe
The fatigue resistance of m-pipe® is a key aspect of the system’s reliable intervention performance, as the pipe can be reeled thousands of times without significant degradation. Such resistance also means that the system can accommodate larger vessel motions during deployment, maximising operational windows and intervention campaign up time.
Magma IDP integrated hydraulic pumping and riser package
The Magma IDP is a single vessel back-deck package that manages all aspects of the m-pipe® riser including transportation, deployment and retrieval. It is compact and relatively lightweight and is specifically designed to fit on the back deck of small light well intervention vessels, construction vessels or even directly onto a stimulation vessel.
- IDP system includes the reeler, controls cabin, power unit, tensioner, level wind and chute
- Deploys 3,000m of m-pipe® in three sections, complete with oilfield standard end fittings
- Riser work platform to safely deploy jumper sections, EDP, ballast weight and buoyancy
- Full support with operational procedure manual and a team of qualified offshore personnel
- Full IDP system and m-pipe riser available as a rental package on competitive day-rates
The IDP shown is designed for 3,000m (10,000ft) of 3in 15ksi pipe but the same unit can also be used for 3in 5ksi or 10ksi pipe.
The pipe is loaded into the reel in three sections and stored in separate partitions, allowing a single, double or triple length to be deployed depending on application depth.
The key benefit of this approach is that it provides operational flexibility and hydraulic efficiency. The latter is important as it avoids the need to pump through the whole pipe length on the reel when deployed in shallow or intermediate well depths.
The IDP also includes all aspects of pipe handling and other equipment such as LRP, EDP, buoyancy and ballast weights, all optimised for safe, efficient and reliable operations, through a moonpool or over the vessel side.
The integrated m-pipe® and IDP system can also be combined with other packages and services from operators to provide a complete, cost effective and reliable service for deep water hydraulic pumping operations, including emergency disconnect packages, subsea tree and manifold connections, Intervention chemical storage and pumping and an ROV spread.
By providing an effective packaged solution to all of the critical technical and commercial components in a hydraulic well stimulation system, including the riser and its delivery system, Magma’s m-pipe® and IPD system facilitates the entire well pumping process, allowing easier access by operators through a day-rate rental system, and increased confidence for contractors to deliver effective hydraulic LWI pumping operations.
The combination of the Magma IDP system and high performance m-pipe® downline ensures ease of operation and allows multiple hydraulic light well intervention operations over a period of many years, taking advantage of the longevity and fatigue resistance of m-pipe® and offering a complete and commercially attractive packaged rental solution.
The Magma IDP system and m-pipe® is set to help to rapidly build a nascent LWI market, allowing operators to more easily take advantage of hydraulic stimulation methods and deliver the additional production at the lower cost per barrel that the oil industry urgently requires.
The limitations of steel pipe versus m-pipe® composite pipe utilising PEEK
Reviewed by Geoff Small, Victrex market Technology Manager
Many variants of high performance steels have the high strength, stiffness and good performance at high temperatures required for subsea oil and gas pipe. However, corrosion is the significant drawback in the use of steel pipe for offshore deployment, estimated to cost the offshore oil and gas industry more than $1.3 billion every year.
Steel corrosion poses an insidious threat which often seriously undermines the structural integrity of oil and gas pipes. Even titanium is susceptible to crevice and pitting corrosion at temperatures above 100°C, conditions that are common in deep water fields.
Some steels can form passive surface layers when exposed to aggressive media, but these layers can be damaged or even completely removed by external subsea erosion, from buckling, wear or damage to the external pipe. Where fresh metal surfaces are regularly re-exposed, the corrosive wear removal rates of material can be highly significant.
Corrosion of steel can be dealt with by a range of techniques such as coating, painting, sacrificial anodes and chemical inhibitors. However, none of these methods is 100% successful, most are expensive and, in the case of inhibitors, they can represent a seriously detrimental environmental threat.
PEEK – the solution to steel pipe limitations for the oil and gas industry
Polymers have long been used in the oil and gas industry on account of their excellent corrosion resistance. The major barrier to their wider uptake has been the lack of mechanical properties in service environments at high temperatures, as even the highest performing thermoplastic polymers such as PEEK lose significant strength and stiffness around 200°C.
This problem is addressed by the use of fibre reinforcement in the form of high performance thermoplastic / carbon composites, where high strength and stiffness is derived from the fibre reinforcement. The most common continuous fibre reinforcements are carbon fibre and ‘S’ glass, which provide combined mechanical properties that exceed those of steel.
Unlike steel, polymers are also inherently more resistant to chemical attack or corrosion. Most thermoplastic polymers have good all-round chemical resistance to sea water, crude hydrocarbons and a range of solvents. Unlike steels, this resistance is based upon a fundamental lack of reactivity in that environment rather than the formation of passive layers.
Unlike some thermoplastics, which can only withstand temperatures of below 130°C, Victrex PEEK polymer pipe benefits from a high level of mechanical strength retention even when temperatures are high, combined with an exceptional chemical resistance to 200°C. Unlike steel, PEEK does not rely on a passive layer build-up, which makes it suitable for subsea applications which involve sea water, potential wear, abrasion and erosion.
Why m-pipe® is the world’s most reliable subsea pipe
The basic building blocks of Magma m-pipe® are Victrex PEEK, carbon fibre and S-2 glass fibre, one of the highest performing glass fibre systems available. Since all these fibres are effectively inert, the chemical resistance of m-pipe® in aggressive subsea environments relies upon the exceptional chemical resistance properties of PEEK polymer.
In the oil and gas industry steels are susceptible to a wide range of corrosion processes, the most widespread type being where steel comes into contact with water to form rust. Both carbon dioxide (CO2) and hydrogen sulphide (H2S) are also catalytic to the corrosion of steel.
Although dry CO2 is not itself corrosive, it dissolves in water to form carbonic acid, which then reacts with the iron to form iron carbide and hydrogen.
In sour corrosion iron reacts with H2S in the presence of water to form iron sulphide, which may form a passivating scale, but is vulnerable to removal. Another feature of hydrogen corrosion is hydrogen embrittlement.
Both these gases can also be readily formed by bacterial activity, sulphur reducing bacteria being a common example. Oxygen promotes corrosion by accelerating the effects of H2S and CO2.
Erosive corrosion occurs where the passive layers are continuously removed by the flow of fluids with particulates over the surface and may be most significant in areas of high turbulence.
In these common environments, PEEK polymer exhibits remarkably good resistance. In an aqueous environment such as sea water there is little effect of ageing on mechanical properties after prolonged exposure, even at temperatures of 200°C.
14 days exposure to seawater at 200°C produces a 4% increase in modulus and a 5.5% increase in strength. Addition of carbon dioxide to the environment and the presence of carbonic acid make little further change and Victrex have measured no effect on mechanical properties at 100°C. Whilst higher temperatures have yet to be fully evaluated, no significant effect is expected.
In the presence of H2S, PEEK shows similar resilience. In industry standard tests such as NORSOK M710 and ISO 23936 where a standard environment contains 10% H2S in the gas phase, there is no change in mechanicals over several thousand hours at up to 220°C, and even 20% sour gas produces no change in strength.
The physical appearance of the polymer also remains virtually unchanged despite its exposure to this hostile environment.
In order to understand the response to H2S better, Victrex has evaluated the performance of PEEK in a 100% sour gas environment and found that it is only above 200°C that any change in mechanical properties begins to develop.
Once again, the appearance of the polymer is almost unchanged by this exposure.
Finally, when considering erosive corrosion, this is not a criteria which affects PEEK at all.
Firstly, there is no passive layer build up on the exposed polymer and, secondly, PEEK demonstrates extremely high resistance to erosion, exhibiting around twice the erosion resistance of steel based on volume of material lost.
Advanced thermoplastic polymer composites such as those utilised in Magma Global m-pipe® provide equivalent mechanical properties to high performing steels over the entire temperature range of both current and future projected oil and gas industry requirements, including those conditions found in deep water and sour service environments.
In addition, thermoplastic polymer composites also have the significant additional benefits of lighter weight (around one tenth that of equivalent steel pipe in sea water) and none of the detrimental corrosion processes suffered by steel pipe.
Since the start of the offshore industry steel has been the structural material of choice for subsea riser systems.
But with the development of new lighter, stronger pipe materials there is a new approach to lightweight subsea riser design.
Reviewed by Stephen Hatton, Magma Global Technical Director.
Steel has served the industry well, and no doubt will continue to do so going forwards. It has allowed the industry to progress from shallow water (150m) to ultra-deep water (3,000m) in the space of just 25 years. This has been achieved by ongoing improvements in steel specification, welding technology and the development of analytical methods, all assisted by the phenomenal increase in computational capacity.
Whether in the form of a non-bonded flexible pipe or rigid pipe, steel has almost exclusively been selected as the material to resist the complex loads that a typical riser must withstand. Steel is the industry ‘workhorse’ material with excellent and predictable structural properties and is manufactured in such volume that it is remarkably low cost.
Where steel comes unstuck
However, the disadvantages of steel are its high density, low resistance to corrosion in seawater and susceptibility to hydrogen embrittlement in a sour environment. In sour corrosion steel reacts with H2S in the presence of seawater to form iron sulphide, which may form a passivating scale, but is usually vulnerable to material removal. These issues are well understood, and manageable with appropriate design methods. However, it is perhaps the high density that causes the biggest challenge for the subsea riser designer and which leads to a nonlinear increase in riser cost with increasing water depth.
As water depths have increased steel riser design solutions have been extrapolated from successful shallower water applications. Whilst there has been some investigation and application of other materials such as aluminium and titanium, steel has remained technically and commercially the material of choice. The challenge presented by the weight of such steel risers has been managed by ever larger buoyancy modules and installation vessel specification, whose capabilities have been extended by upgrading and new builds. Consequently, Tier 1 installation vessels are orders of magnitude more capable than 20 years ago with respect to riser payloads, crane capacity, station keeping, reel storage capacities and deck payload. The downside is that these vessels also have associated higher day-rates.
But the combination of ever increasing riser weight, buoyancy requirement, and vessel payload and installation vessel cost means that deep water risers are now a substantial percentage of the total development cost, and are often the most technically challenging and schedule critical aspect of a deep water development. This adds to the industry challenge of ever increasing offshore development costs, and the fact is that such developments must be competitive with other hydrocarbon sources. In this period of low oil price, such deep water developments are increasingly hard to justify.
Industry responses to the subsea riser challenge
The oil and gas industry therefore needs to find more cost effective solutions to the riser challenge, to reduce high Capex where riser projects typically carry budgets of c. £2.5bn and, additionally, address the high Opex that arises from the need to manage corrosion and general riser degradation and susceptibility to damage that steel risers can suffer from. In achieving these aims a diametrically opposite design approach to the use of steel can be considered. This uses sophisticated, lightweight materials such as carbon fibre, both for both the riser pipe and the buoyancy modules. For the pipe element, for example, this design approach can achieve pipe weight in water that is 90% less than steel and is also highly resistant to corrosion.
For the buoyancy elements the composite solution reduces the effective density from around 350kg/m3 to less than 90kg/m3. This greatly simplifies all aspects of installation but, most importantly, reduces drag loads and added mass and hence improves overall riser response.
There is little doubt that such materials can offer enabling capabilities to access hydrocarbons in ultra-deep water beyond 3,000m. The key question is whether this lightweight design approach can help reduce the cost of subsea risers in the medium to deep water depths, 1,000 to 2,500m, making such solutions preferable over the standard steel design approach?
In the case of free standing risers (SLORs), which seem the preference for many medium and deep water fields, the use of steel pipe and steel buoyancy modules produces a negative design spiral where high weight leads to high drag loads, requiring more tension and more high drag buoyancy. This leads to a riser design which is structurally and hydro-dynamically inefficient, and also needs a high cost vessel for installation. Additionally the riser payload on the vessel can be high and, since all aspects of the design, procurement and installation processes are on the limit of feasibility, both the installation contractor and operator carry significant risk despite the solution being ‘proven technology’.
The Magma m-pipe® subsea riser solution
To tackle this situation Magma has developed an alternative riser design approach, where the solution allows the reduction of both weight and drag loading. This produces a greatly improved riser response, where all key parameters such as buoyancy module size, installation loads, foundation loads are very significantly reduced. In this manner, a more cost effective riser solution is achieved, despite the higher unit cost of the pipe material and where the increased material cost is offset by savings in buoyancy costs and vessel installation costs. It’s simply a different design approach, made possible by application of modern materials and ultimately delivering lower costs and lower risk.
There are similar analogies to the above approach in the aerospace industry, where increased use of composite materials is now standard practice to save weight and achieve improved fuel efficiencies. But, whilst the offshore oil and gas industry has made some significant technology steps in the last 30 years, in the riser space there are few technology innovations of true significance.
In the riser space, technology development has been limited to incremental steps, partly to mitigate risk and partly driven by market constraints. To make a switch to composites from steel is not an incremental step, and some would say it’s a leap of faith. However, the cost analyses conducted show that significant cost and performance benefits can be achieved.
In this current period of low oil price, it is likely to put pressure on riser cost reduction, and increase the appetite for new solutions that can deliver life of field cost benefits. It is believed that composite technology can offer this not just for ultra-deep and aggressive reservoirs, but also as a way to reduce the cost and increase performance of less challenging developments currently considered marginal.
- Download a PDF fact sheet version of this blog on lightweight riser design
- How an m-pipe m-SLOR lightweight riser design saves 43% versus a steel pipe SLOR
The future of well intervention techniques in a low oil price environment.
Reviewed by Stephen Hatton, Magma Global Technical Director.
Even with active reservoir pressure maintenance, through water injection, the productivity of wells deteriorates with time.
Sometimes this occurs gradually over a period of years but often relatively quickly over a period of months, requiring regular well intervention.
Commercial viability of many wells is therefore often dependent on being able to intervene and rectify any downhole issues that may further limit production rates, in order to maximise their commercial life. Read More
High performance m-pipe® composite pipe is ideal for use in subsea production systems.
m-pipe® is a unique high quality, high strength and low weight carbon and PEEK polymer pipe with a monolithic structure from bore to surface, providing superior performance in deep water and harsh offshore conditions. This is due to its light weight, high strength and resistance to corrosion, chemical attack and fatigue loading, delivering significant reductions in subsea project risk and subsea project cost for offshore field development and operation.
m-pipe® has the potential to simplify piping design issues and to simplify installation procedures and operational activities for improvements in long term reliability, such as a reduced need for inspection, maintenance, repair or replacement.
The low weight of m-pipe® (around 1/10th that of steel in water) allows it to be deployed in configurations not possible with steel or non-bonded flexible pipe, either due to weight or axial compression limits. m-pipe® also has a high strain capability ten times that of steel, plus an ability to accommodate axial compression loads without birdcaging or excessive fatigue damage rates.
This allows m-pipe® to be deployed in configurations not possible with steel or non-bonded flexible pipe, either due to weight or axial compression limits.
m-pipe® also delivers proven cost savings, for example through a reduction in the need for large riser buoyancy modules or the capability to use smaller well intervention vessels.
Magma has created an animation to show the primary riser, jumper and intervention applications of m-pipe®.