MED OIL GAS Magazine 2017 by Rosendahls_online

Magazine 2017 1

FASTER BROWNFIELD PROJECT EXECUTION

WITH CADWORXÂ® & ANALYSIS SOLUTIONS

CADWorx & Analysis plant design and engineering solutions are easy to use; flexible, scalable and trusted by over 80% of the leading plant engineering companies and owner operators worldwide to deliver accurate and reliable results. The solution suite matches the requirements of dynamic brownfield projects and help customers across the world to deliver projects onschedule and on-time, every time. Visit our website to learn more about the toolset that caters for any project type, scope, or complexity from the smallest skid to the largest plant. hexagonppm.com

ÂŠ 2017 Intergraph Corporation d/b/a Hexagon PPM. Hexagon PPM is part of Hexagon. All rights reserved. Hexagon PPM and the Hexagon PPM logo are trademarks of Hexagon or its subsidiaries in the United States and in other countries. Other brands and product names are trademarks of their respective owners.

Content

Features Mercury Engineering-case study- improving design and construction efficiency...................................... 6 Challenges of monetizing and exporting East Med gas to the global market.......................................... 23 Tracerco: Inspecting Unpiggable Pipe Systems........................................................................................ 29 Societe Generale Corporate & Investment Banking- Oil Quarterly Report............................................... 34 Geological & Geophysical case study- Multi-phase thermal history and itâ&#x20AC;&#x2122;s impact on Hydrocarbon Development (Algeria)...................................................................................... 45 Marex Marine- Role of the IMO in the Offshore Industry........................................................................ 51 Technology- Practical Application of Energy Storage in Hybrid Commercial Vehicles.............................. 55 SafeKick: Beyond MPD-Introducing Enhanced Primary Well Control...................................................... 63 The Well Academy- Level 5 Training Solutions ....................................................................................... 69 Tolomatic- conventional and emerging technologies for valve actuation and automation....................... 79

Special Focus: Malta Mediterranean Maritime Hub Ltd............................................................................................................ 11 Malta Petroleum Exploration Opportunities............................................................................................ 14 Malta applies to the EU for clearance to offshore exploration................................................................. 19

Conferences.......................................................................................................................... 10, 43, 67, 83 Companies in the news SubCtech unites ocean engineering and offshore technology................................................................. 71 Liebherr strengthens maritime business out of Australia ........................................................................ 73 NDT Global Identifying and Characterizing ............................................................................................ 76

Published by: A J & P Production,Med Oil & Gas Magazine: Malta & Dubai Website: medoilandgas.eu Printed & designed by: Rosendahls a/s Denmark Cover photo courtesy of Transocean Ltd.

4 | MED OIL & GAS | November 2017

Preparing for the energy boom Following OPECâ&#x20AC;&#x2122;s decision to increase supply, oil market prices plunged from over $100 per barrel in 2014, to below $40 per barrel in 2015. Many companies in the oil industry have suffered severely during the downturn due to high operating costs throughout the sector, creating a market ripe for mergers and acquisitions. Countries with oil-based economies, such as Venezuela and Nigeria, have also strongly suffered. Development of new energy and civil infrastructure has also been affected. Lower oil prices have reduced the competitiveness of LNG and renewables, which have traditionally been cheaper than oil, reducing investment in these areas. Uncertainty over the timing and price level of oil recovery has created a stagnation of large investments in energy infrastructure and cost cutting policies. When oil hit lows earlier this year many companies began exploring how they could sustainably operate at $40 a barrel. Fundamental changes have been seen in the supply chain, opening the door to new global players as companies look for innovations to improve cost efficiency. Classification societies and consulting engineering companies are moving from their traditional roles solely as service providers to become strategic advisors for the industry. Highly valued services such as these are also justifying better rates in the face of the downturn, with larger companies committing to larger tenders as they look to overhaul and significantly improve their operations.

Increased investment in large tenders from oil majors in particular has been seen, upgrading their facilities to improve cost efficiency prior to the next oil boom in order to come out on top when it arrives. Although this may seem counter-intuitive, the companies that are able to invest and collaborate now will be more competitive, have strong relationships with industry stakeholders and customers, and be able to provide interesting products thanks to the groundwork they laid before the boom.

Comments from Andrea Bombardi andrea.bombardi@rina.org

This is the time to think about new services and approaches that are innovative and fit for purpose to meet upcoming challenges, such as the skills gap, reductions in CO2 emissions, lowering operating costs, efficiency of business processes, standardisation of technologies to help the industrial internet grow and collaboration to aid worldwide growth. Despite considerable turmoil throughout the sector over the past two years, forecasts are beginning to suggest that the oil price will stay at a reasonable price in order to allow a further growth of the market. Itâ&#x20AC;&#x2122;s now time to bite the bullet and grab opportunities in the energy market before the boom comes. History is cyclical as Giambattista Vico predicted: it adapts to the current market. Focusing on investment is the recipe to laying the foundations for a booming new era.

Mercury Engineering improves design and construction efficiency by integrating CAD and as-built point cloud data Irish engineering services provider enhances schedule certainty and ability to design and build Right First Time with CADWorx® & Analysis Solutions

FACT S

Identifying goals

AT A GLANCE

Company: Mercury Engineering Website: www.mercuryeng.com Description: Mercury Engineering is a leading European contractor specializing in the provision of mechanical, electrical, fire protection and technology services to a range of sectors including commercial, data centres, manufacturing, infrastructure and healthcare. Mercury has a reputation for getting the job completed on time, within budget and to the highest quality, making them a contractor of choice for industry leaders for 40 years. Industry: Semi-conductor, oil and gas, pharmaceutical, healthcare, food and beverage, building services, datacenters Country: Ireland / Europe Products used: • CADWorx® Plant Professional • Isogen® • Leica CloudWorx Key benefits: • Schedule certainty due to ability to track progress better • Ability to design and build Right First Time due to access to accurate as-built data • Reduced labor onsite due to the ability to generate trusted high-quality isometrics

6 | MED OIL & GAS | November 2017

Mercury Engineering was contracted to upgrade an existing process plant. The project scope was the design of a new process plant with product pipelines that needed to connect into an existing facility. To achieve this, it was necessary to route the new pipelines along an existing pipe bridge, and across the roof of the existing structure and into a new building. The main goal of the project was to shorten the project schedule by maximizing the amount of piping pre-fabrication that could be completed off-site before piping installation was performed on-site. To meet this goal, and ensure that the new piping would fit when erected, Mercury Engineering needed as-built information of the existing facility.

Overcoming challenges Unfortunately existing as-built information was lacking, therefore the initial challenge was how to capture the as-built situation quickly and accurately. To ensure successful on-time project delivery, Mercury Engineering determined that it would be necessary to laser scan the existing building, roof space, and pipe bridge. This would provide an ac-

The new piping connected with the existing tie-ins

Connecting the old facility with the new building

curate design basis for the new pipe routes and tie-ins that had to be designed. Having this information available would also help to ensure and guarantee that the new piping would fit on the pipe bridge and could be constructed inside the existing building without clashing. Particular attention was paid to the tie-in points, and extra scans were done in these

areas to ensure that enough detail was captured to accurately design the tie-ins. After this, Leica CloudWorx in combination with CADWorx Plant Professional was used to manipulate the piping route to match the scanned as-built positions of the new tieins and to accurately design them. Visualization of the pipe bridge inside the CAD system helped to identify space for the new pipelines, enabling them to be routed eas-

ily alongside other existing services, which made connecting the old and new building seamless. The pipework installation was detailed before the new building was constructed. As the building was being erected and took shape, it was laser scanned, and the new point clouds were integrated with CADWorx Plant Professional. Using CloudWorx in com7

FASTER PROJECT EXECUTION CADWORX® & ANALYSIS SOLUTIONS CADWorx & Analysis plant design and engineering solutions are easy to use; flexible, scalable and trusted by over 80% of the leading plant engineering companies and owner operators worldwide to deliver accurate and reliable results. The comprehensive series of design tools include structural steel, equipment, process & instrument diagrams, design review, as well as automatic isometrics and bills of material. CADWorx Plant Professional is also integrated with the Hexagon PPM’s Analysis solutions to enable you to deliver projects faster than ever before.

hexagonppm.com © 2017 Intergraph Corporation d/b/a Hexagon PPM. Hexagon PPM is part of Hexagon. All rights reserved. Hexagon PPM and the Hexagon PPM logo are trademarks of Hexagon or its subsidiaries in the United States and in other countries. Other brands and product names are trademarks of their respective owners.

INTERGRAPH® PP&M REBRANDED TO HEXAGON PPM Intergraph® Process, Power & Marine (Intergraph Corporation) has rebranded to Hexagon PPM in June 2017. Hexagon PPM is focused on delivering end-to-end information technology solutions that drive efficiencies during the design, construction and operation of industrial facilities and large-scale construction projects. Connecting the old facility with the new building

bination with CADWorx, Mercury Engineering was able to make minor modifications to the pipework as the project was on-going, to align the routings and to make changes to the overall design to reflect the changing as-built condition of the new building. This additional site-check increased confidence in the accuracy of the isometrics issued to the fabrication workshop, which were auto-generated via Isogen directly from the CADWorx design model. In doing so, Mercury Engineering ensured that the piping would fit first time, and avoided unnecessary fabrication rework on-site, helping to keep the project schedule on-track.

Realizing results For this project, Mercury Engineering needed a solution that was able to detail mechanical, electrical, and HVAC (heating, ventilation and air conditioning) design as well as produce trusted, high-quality, industry standard piping isometrics. The company selected Hexagon PPM’s CADWorx Plant Professional due to this breadth of modelling capabilities, cost-effectiveness, and its ability to produce 2D deliverables in DWG formats. Another key reason was the short learning curve and ease of use – Mercury’s staff new to the product required only 3 days of training before they were productive. In addition, Mercury Engineering was already familiar with the ease-of-use of CADWorx solutions as the company’s BIM (Building Information Modelling) group has successfully used the solution for over three years. Additionally, Mercury had previously developed industry-specific CADWorx format

catalogue and specification content for other projects, which included their SAP part coding. Due to this, Mercury were also able to accelerate their procurement process and take delivery of materials for the project using the material control (BOM) reports produced by Isogen. Mercury Engineering received significant benefits from using Hexagon PPM’s CADWorx solution on their project: • •

•

Schedule certainty due to ability to track progress better. Ability to design and build Right First Time due to access to accurate as-built data inside the CAD environment. Reduced labor onsite due to the ability to generate high quality isometrics, which helped to avoid the need for onsite fabrication.

Moving forward Mercury Engineering uses CADWorx Plant Professional solutions to manage 3D graphical and material information. Currently, more than 1.48 terabytes of data is handled across their active projects. The company has 27 active users of the software working on 4 new projects currently.

Because of Intergraph’s market-leading position and reputation, Hexagon PPM products will continue to carry the Intergraph brand name. “PPM” is retained as a nod to the key industries of process, power, and marine; however, Hexagon PPM will expand its base to serve industries beyond its traditional core. About Hexagon PPM Hexagon PPM is the world’s leading provider of enterprise engineering design software and project control solutions. By transforming unstructured information into a smart digital asset, our clients are empowered to visualize, build, and manage structures and facilities of all complexities, ensuring safe and efficient operation throughout the entire life cycle. PPM is part of Hexagon (Nasdaq Stockholm: HEXA B; hexagon.com), a leading global provider of information technology solutions that drive productivity and quality across geospatial and industrial landscapes.

Ciaran McCreary, 3D VC / BIM engineer at Mercury Engineering commented on the company’s experience of CADWorx tools: “We were very happy with the Hexagon PPM staff who performed our training and implementation services. Using CADWorx tools enabled us to get started immediately – we were able to produce fabrication isometrics immediately after completing our coordination process.” 9

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MEDITERRANEAN MARITIME HUB The Mediterranean region is a highly prospective one, with globally-significant onshore and offshore hydrocarbon reserves, and wide geographical distribution. Oil and gas activity in the territory is also increasing, as can be witnessed through recent approvals to develop fields in the region. This will result in an increase of exploration, drilling and production activity. Malta is strategically located in the centre of the Mediterranean – perfectly-placing it to serve the marine, oil and gas industry. As a result, the Maltese cluster is thriving and growing year-on-year, attracting new companies to relocate here and open offices on the Island. Beyond this, a multi-million-Euro project was recently launched in the heart of Malta to entice even more companies in the industry to it. In 2016, MMH Malta Limited entered into a 65-year emphyteutical grant with the Maltese Government. To develop, manage and operate the facilities at the former Malta Shipyard Yard in Valletta Port, transforming them into The Mediterranean Maritime Hub – a world-class regional hub capable of supporting and sustaining the most challenging oil and gas industry operations anywhere in the Mediterranean and North African region. The Mediterranean Maritime Hub is a 42acre port facility established to deliver reliable, cost-effective marine, oil and gas industry support services across the entire region. Working in the strategic and historic port location of Valletta, the Hub is a Freezone/ Customs Bond Facility offering 1,200 linear metres of quaysides, external equipment laydown and storage areas. It also boasts extensive covered warehousing to handle,

maintain and store a range of cargo and engineering fabrication sheds. Through the Hub, MMH Malta enables: • ‘fit for purpose’, full supply chain support for the marine, and oil and gas industry, in a single location that is accessible from anywhere in the Mediterranean • integrated services provision and project planning, which, together with new ways of working, provides faster turnarounds, leaner crews, more efficient operations and reduced asset non-productive time • high-quality repeatable and reliable service support to company operations anywhere in the region

• local content-compliant ‘Regional Reach’ capability, which can help companies better manage and mitigate their operational risks in particularly challenging geographies. 11

MMH Malta Ltd also provides a selection of support services, ranging from vessel maintenance and repair to inspection and certification, global logistics services, and the provision of competent personnel and training. All of the MMH’s services are designed to speed up turnaround time and improve cost efficiencies for companies operating within the marine, and oil and gas industry. Paul Abela, Chairman of MMH Malta, says, “We realise that companies operating within these industries face challenging market conditions. Thus, their first approach might be to cut costs and capabilities but, what if there was an option to reduce costs whilst maintaining capability in order to emerge

from the downturn in a stronger position than their competitors? “The MMH is perfectly suited to this purpose. Developed with the full support of the Maltese government, it is focused on creating a full-service facility that allows marine, oil and gas industry clients to maintain capability in the Mediterranean region, while reducing operational costs and overheads related to over-capacity.” Steve Colville, CEO of the Mediterranean Maritime Hub, is very clear about the Hub’s value offering. He says: “The two things we are doing that make an immediate difference are to provide the services that clients

only need occasionally but are expensive to sustain fulltime in-house, and to work more closely together so that planning is improved and logistical requirements can be better anticipated.” Colville goes on to explain how clients can reduce further costs by adopting the Lean Crew Model. “MMH can offer direct access to its own multi-skilled workforce. Our ‘Lean Crew’ model supplies you with who you want, when you want them and only for as long as you need them. This flexibility reduces personnel overheads, the non-productive time associated with projects and provides a rapid project-based mobilisation & demobilization.” “The intention is to enable companies to have a smaller operational footprint in challenging areas of the Mediterranean by having a reliable support base, with everything they need, centrally located on Malta.” Colville concludes that “the Hub is designed to make Malta the unique regional centre of excellence for the services needed by the oil and gas industry.” With regards to the investment of the Hub’s infrastructure, MMH Malta has already inputted substantial funds into the dredging of the sea area, to increase the draft to 10.5 m. A second phase of the dredging project will further increase the draft to 12m. Be-

12 | MED OIL & GAS | November 2017

yond that, additional investments will include the widening of the existing dock to enhance the berthing facilities within the Port, the construction of a travel lift with the capability to lift up to 800 tons, and a floating dock. This investment will be carried out over the next three years.

operational reputations and commercial bottom lines. Apart from the mandatory industry courses like Well Control, CompEx and Marine Licencing, the Academy can also help companies develop tailor-made courses that suit their specific needs.

Mr Abela, comments: “We are developing the Hub’s infrastructure whilst keeping in mind that this is a national asset, so we feel an immense responsibility in that respect. We want this project to be a facilitator for operators in the industry to grow their business.”

Angelique Maggi, director of the MMH Academy, comments: “The Academy is crucial to the Hub’s operation as it readies our workforce with the right safety culture, knowledge and skills. After all, our people are also a key element in making the Hub project a success.”

Apart from investing in the infrastructure, MMH is also investing in the people associated with the Hub. The MMH Academy was created in 2015 to provide holistic training solutions to the industry and to deliver a competent workforce, enhancing clients’

Whilst MMH is Malta-based, it is not Malta-confined. MMH can support client operations anywhere in the Mediterranean region through its networks, delivering the same high levels of service and support one would enjoy in our home base.

With all of this in mind, there is no doubt that the MMH is already an asset for the industry. Now it will go on to become an enduring key enabler for efficient, cost-effective and safe operations in the Mediterranean, as the region increases in importance within the global energy sector.

Paul Abela Chairman of MMH Malta Ltd.

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Malta Petroleum Exploration Opportunities Introduction The Maltese Islands are strategically located in the centre of the Mediterranean close to producing oil and gas fields in offshore Sicily, Libya and Tunisia. These include the Ragusa (200 MMbbl), Gela (150 MMbbl) and Vega (125 MMbbl) fields in southeast Sicily, the Ashtart (310 MMbbl) and Miskar (800 Bcf) fields offshore Tunisia and the Bouri (3.7 Bbbl & 1.9 Tcf) field offshore Libya (Fig. 1). The Panda cluster is another recent gas discovery in southwest Sicily. All of these fields produce from geological formations which are analogous to those found offshore Malta. Malta’s offshore acreage (Fig. 1) is divided into seven exploration and production designated areas covering a surface area of over

75,000 km2. These areas lie in water depths ranging from less than 50 m to depths greater than 3,000 m. Area 3 and Area 4 are subdivided into eight and seven blocks respectively. Malta’s prospective petroleum geology, its favourable fiscal regime, modern infrastructure and stable political climate make petroleum exploration opportunities competitive and attractive.

Exploration History Malta is a frontier exploration region and still relatively underexplored. The actual search for oil in Malta started in 1954 when D’Arcy Exploration Company (later British Petroleum) carried out a geological and geophysical survey on the island to correlate

its sub-surface geology with that of southeast Sicily where oil had just been discovered in Ragusa. The 3,000 m onshore well, drilled right after the enactment of the Petroleum (Production) Act in March 1958 did not find any oil or gas. Following the introduction of the Continental Shelf Act in 1966, exploration efforts were focused offshore. Several seismic surveys, both regional and close grid, have been acquired and a total of 11 offshore wells have been drilled. Although some wells encountered hydrocarbons such as offshore wells Alexia, Lampuko and Tama and onshore well Madonna Taż-Żejt yet no commercial discovery has been made and Malta is still not an oil producing country.

Geology and Petroleum Systems Fig 1. Malta’s offshore acreage and major fields in the Central Meditiranean

Offshore Malta forms part of the Pelagian Block, a stable promontory of the North African continental margin since the Permo-Triassic. The stratigraphy of offshore Malta (Fig. 2) can be attributed to three dominant paleo-depositional domains: (i) stable carbonate platforms; (ii) subsiding basins off the platforms; and (iii) transitional carbonate ramps and rimmed shelves along the platform-to-basin margins. Several proven petroleum systems present in adjacent areas are inferred to extend into offshore Malta.

Source The Late Triassic Noto Formation and the Liassic Streppenosa Formation are the main source rocks of the Streppenosa Basin which extends offshore Malta. The Noto Formation is a rich and prolific source with a maximum organic content of 13%. The Streppenosa Formation is poorer in organic content but its greater thickness makes it a source to large volumes of oil. 14 | MED OIL & GAS | November 2017

Formation is the reservoir in the Gela and Ragusa fields. The Siracusa Formation consists of dolomitic limestones deposited in a sub-tidal to inter-tidal platform environment on carbonate highs contemporaneous with the deposition of the Streppenosa Formation along the basin margin and the deep basin. The reservoir quality of the Siracusa Formation reaches porosities of 12-16% in the Vega field. Cretaceous reservoirs have been encountered in several wells offshore Malta sharing similar characteristics to reservoirs in offshore Tunisia. These include the Early Cretaceous Serdj Formation, Cenomanian rudist limestones of the Zebbag Formation the Late Cretaceous Aleg Formation and Campanian-Maastrichtian limestones of the Abiod Formation. Porosities range from 5-14% for the Serdj Formation to 8-27% for the Miskar/Bouleb/ Bireno members of the Aleg Formation. Another prolific reservoir offshore Libya and Tunisia is the Early Eocene El Garia member of the Metlaoui Formation which was developed across extensive carbonate ramps. Similar depositional settings are inferred to have developed offshore Malta.

Seal In the Streppenosa Basin, a widespread transgression at the end of the Liassic deposited a sequence of marls, marly limestones and cherty limestones of the Buccheri Formation on the horst and graben complex developed since the Triassic providing a seal for the underlying Gela and Siracusa reservoirs. On the platform, this formation was thinly deposited or subsequently eroded.

Fig 2. Stratigraphy of offshore Malta and surrounding regions

pre-dates the generation and expulsion of hydrocarbons.

The Tertiary Bou Dabbous and the Cretaceous Bahloul-Fahdene source systems are inferred to extend into Areas 4, 5 and 7 of Maltaâ&#x20AC;&#x2122;s offshore acreage. The Bahloul Formation is a widespread source rock consisting of black laminated limestones and marls with an organic content of between 4-21%.

Reservoir

Thermal and migration modelling of basins offshore Malta indicate a thermal regime that compares favourably with other producing basins in the Pelagian Block. In addition, the formation of the main traps

The Gela Formation consists of dolomitised algal calcarenites deposited on an extensive tidal flat prior to the onset of rifting. Its primary porosity is typically less than 2-3% but is enhanced locally by fracturing. The Gela

The principal reservoirs of the Streppenosa Basin are the Upper Triassic Gela Formation and the Liassic Siracusa Formation.

The extent of deposition of sealing shales and marls in offshore Tunisia is very widespread and extends eastwards up to the Melita-Medina Platform offshore Malta. Cenomanian Fahdene shales, Senonian Aleg shales, Late Maastrichtian-Paleocene El Haria shales and Late Eocene Souar shales are all proven seals.

Prospects The main targets of the exploratory wells drilled in the early 1970â&#x20AC;&#x2122;s were large anticlinal structures located on the platform areas. Exploration drilling in these areas encountered porous reservoir rocks but limited source and seal. With nearly all the drilling activity to date being on the platform, the geologic environments most conducive to commercial hydrocarbon accumulations are yet untested. 15

Fig 3. Beta prospect â&#x20AC;&#x201C; A Late Cretaceous carbonate build-up

Seismic data in the seventies did not permit sufficient good quality imaging to identify other traps located close to the shelf edge margin. Recent advancements in seismic technology such as broadband and long-offset seismic allow a much better definition of the sub-surface for the delineation of more subtle traps. New seismic data and prospectivity studies show that exploration should focus on the shelf edge areas and intra-basinal highs, which are better placed for source deposition, seal preservation and charge access. An example of each is given below:

Beta Prospect Seismic data indicates the extension of the Streppenosa Basin in Blocks 4 and 5 of Area 3 and the presence of basinal facies of the Noto/Streppenosa source rocks and the Buccheri seal. A number of structures/ build-ups have been mapped along the Mesozoic shelf edge both at Cretaceous and Jurassic level.

Fig 4. Comino prospect â&#x20AC;&#x201C; An intra-basinal Jurassic high

with 4-way dip-closure observed at the Top Siracusa and Top Hybla levels. The delineation of the prospect has been confirmed following recent mapping of reprocessed and new seismic data acquired in 2014. The target depth is 4400 m at a water depth of 520 m. Recent 3D basin modelling indicates that the Streppennosa source present in Block 2 of Area 3 is a mature source with onset of hydrocarbon oil expansion starting in the Cretaceous and continuing to present.

Legislation and Licensing Petroleum licensing and petroleum activities in Malta are regulated through the Petroleum (Production) Act and the relevant regulations under this act. The Continental Shelf Act extends the applicability of the Petroleum (Production) Act from territorial waters to the entire extent of the continental shelf. Malta presently adopts an open door licensing policy and suitably qualified oil companies may apply for two types of licences:

Comino Prospect

(1) An exploration licence through an Exploration Study Agreement, which has a term of two years. The work programme normally includes seismic acquisition but excludes drilling. This licence is exclusive and provides the licensee the right to convert the licence to an exploration and production licence.

This prospect is located approximately 30 km north of Gozo in Block 2 of Area 3 (Fig. 4). It is a wrench related anticlinal structure

(2) An exploration and production licence through a Production Sharing Con-

The late Cretaceous objective (Fig. 3) is located on the Mesozoic shelf edge in Block 4 of Area 3 east of Malta. The top of the build-up is at a depth of 1650 m and a water depth of 270 m. The build-up appears to be capped by a shale sequence deposited during a late Cretaceous transgressive episode.

16 | MED OIL & GAS | November 2017

tract. This licence has a term of 30 years and consists of an exploration period of 6 years with the remaining period allocated to exploitation. The exploration phase is divided into two or three phases and during each phase the licensee is obliged to drill an exploratory well. Taxation is at 35% and the licensee can recover all the exploration and development costs from the profit oil. A 50% investment allowance of initial investment costs is also granted for developments in waters greater than 200 m. The Government of Malta through the Continental Shelf Department is committed to increase exploration activity offshore Malta and interested companies can visit the website continentalshelf.gov.mt or contact The Director General (Continental Shelf Department) on dgcs.opm@gov.mt for further information.

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Malta applies to EU for clearance to offshore exploration European Commission has recognized as a Project of Common Interest; and through support for renewable energy and energy efficiency projects to meet the 2020 targets and beyond1. In order to overcome the growing request for electrical energy, the Malta–Italy Interconnector was inaugurated in April 2015, connecting the Italian station located in Ragusa (Sicily) to the Maltese station located in Malta at QaletMarku, Bahar ic-Caghaq. The electrical distribution grid in Malta is spread over four voltage levels, which are: 132 kV; 33 kV; 11 kV; and 400/230 V. The frequency of the supply of electrical energy in Malta is 50 Hz, like the European electrical grid.

PKF Malta is primarily a licensed accounts and audit practice, part of the PKF International global family of legally independent firms consisting of over 400 offices, operating in 150 countries across five regions. PKF Malta specialises in providing high quality audit, accounting, tax and business advisory solutions to international and domestic organisations in all our markets. Current and changing market trends have moved towards diversification of company services portfolio, and in the process immigration solutions along with statistics, economics and mathematics based studies on hot-topic-subjects becoming a niche service that PKF are well resourced to offer successfully. Under this realm, our company undertook an analysis of one of the biggest

challenges our future is faced with, that is, energy supply. Malta’s energy mix is today based on three main components: Onshore power plants, the interconnector to Italy and renewable sources. The new energy strategy is being implemented through a clear roadmap which includes various milestones. These include: switching from heavy fuel oil to a much cleaner fuel, natural gas; upgrading and making sure efficient generation capacity to ensure sufficient electricity to meet future demand, increased efficiency and significantly lower emissions; interconnection link with mainland Europe for both electricity, which was energized in 2015, and also through a planned gas pipeline, which the

In the last years the average electricity maximum demand was quite stable. The overall all-time peak was 438 MW, as registered in July 2015. The local energy demand is reflective of a significantly high seasonal component, due to the hot weather, number of tourists, and increasing number of commercial activities. It is easy to forecast an increase in both the energy demand and the peak demand in the future years, because of the flourishing economy of the Maltese’s Islands. The forecasted future demand is of

1 Minister – Office of the Prime Minister, (N/A), The National Renewable Energy Action Plan 2015 – 2020, Source: https://energywateragency.gov.mt/en/ Documents/National%20Renewable%20Energy%20 Action%20Plan%20(2017).pdf

about 2500 GWh2. As for renewable energy, it accounts for just 5% of the actual internal demand and is composed only of Photovoltaic panels inshore. Due to the size of Malta it is estimated that the maximum capacity of PV’s inshore installation is of about 200MWp3. Where it concerns future energy roadmaps and related oil exploration initiatives, the results are clear to all: Malta has the worse oil exploration record in the Mediterrane-

2 Minister – Office of the Prime Minister, (N/A), The National Renewable Energy Action Plan 2015 – 2020, Source: https://energywateragency.gov.mt/en/ Documents/National%20Renewable%20Energy%20 Action%20Plan%20(2017).pdf

an with only 13 wells drilled in the past 60 years. This in stark contrast with 6,000 wells tested in Italy, and 500 dug in Israel. Due to the economic benefits of abundant gas discoveries in the Levant basin, it is expected that producers will try to find safe export through cross-border pipelines to reach northern Europe and loosen existing Russian dominance. Reuters were quoted saying that turmoil in Libya has given a fresh spur to energy companies looking for big finds further afield to supplies from more politically stable countries. Undoubtedly Malta is geographical well situated to offer investors the potential of untapped offshore reserves which, if successfully marketed, could offer tempting terms for explorers without the security risks plaguing Syria, Iran and Libya. It might be a good time to seriously start

exploration in our relatively untapped Con3 Minister – Office of the Prime Minister, (N/A), The National Renewable Energy Action Plan 2015 – tinental Shelf emulating the successes reg2020, Source: https://energywateragency.gov.mt/en/ istered in Cyprus, Egypt, Libya, Israel, Italy, Documents/National%20Renewable%20Energy%20 Tunisia 35_50_OilGas_9-10_2016_ark3_Layout 1 29.09.16 10.44 Side and 43 Algiers. Ideally, any future gas Action%20Plan%20(2017).pdf

20 | MED OIL & GAS | November 2017

discovery should coincide with the plan to lay an underwater gas pipe linking Malta to Italy. At this junction, it is opportune to give some information on exploration progress reached by countries located in the central and eastern Med basin. To start with, to our north lies the largest offshore field in Sicilian waters termed the Vega and others which were discovered in the mid-fifties. Naturally to the south lies the oil rich Sirte Libyan offshore basin and to the west the equally prolific Tunisian wells. It is encouraging to note how North African offshore fields have been extensively explored and only two years ago Egypt announced the discovery of the offshore Shorouk Concession, which contains the massive Zohr gas field—the largest natural gas field ever discovered in the Mediterranean. It is estimated to contain 30 Tcf of gas according to Italian energy firm Eni. Moving on to the Levant basin we notice how Israel itself has made some of the biggest discoveries so far. In 2009, companies exploring in Israeli waters found the Tamar

field, containing some 8.4 trillion cubic feet of gas. Another discovery by Noble Energy announced the larger deep-water Leviathan field with 16 trillion cubic feet of gas. It is encouraging to note that Cyprus and Israel have signed a memorandum of understanding to cooperate on energy, which would direct Israeli gas exports to the proposed $15 billion three- to eight-train LNG export facility in Cyprus offering access to both European and Asian markets. It discovered a gas field termed Aphrodite with more gas than can be used by Cyprus’s population, leaving around 90% available for export.

while gas demand anticipated to be higher. To face European demand there is the necessity of investing in new wells, but due to the market’s actual troubles and the high cost through European countries to conduct such researches, we are well below the potential explorations.

Over 50% of the EU’s natural gas continues to be sourced from various countries within Europe, with decades worth of production potentially available. In the context of Energy Union objectives, domestic production is often an important aspect in the development of trading hubs and competitive gas markets. The world’s energy production is nowadays facing big challenges. As a result of the lower oil price, global oil and gas producers have cut costs, postponed projects and reassessed priorities. High cost areas such as in Europe have been particularly impacted by the challenging commercial context. This is important because domestic production is particularly relevant to EU energy security, supply diversity and sustainability: for example, even with today’s lower oil price, there are opportunities to better support European natural gas exploration and production, and encourage continued investment.

Exploration in Europe is significantly lower that it was a few years ago, with Norway being the exception. The material discoveries in offshore Egypt demonstrate the potential for similar discoveries in and around Europe and have to be followed.

In its 2015 World Energy Outlook, the International Energy Agency published a number of scenarios taking into account key energy and climate trends by fuel, region and sector for the period 2013 to 2040. In Europe oil and gas accounted for more than 55% of the energy demand in 2013 (total demand was 1,624 Mtoe). After COP 21, energy and climate policies should now be consistent with the IEA’s 450 scenario, which establishes a framework in which there is a 50% chance of limiting the long term increase in the average global temperature to well below 2 degrees Celsius. However, when applied to world energy demand, the 2 degrees scenario has a different impact, as oil and gas demand would remain almost unchanged. There would therefore be less oil and gas demand in Europe, but the global share remains constant. In the future, the oil demand is expected to be lower

Europe is a generally highly mature operating region, with high costs. New discoveries tend to be smaller and technically challenging, requiring significant investments to develop. This is also the case for offshore Romania in the Black Sea.

The positive policy and demand signals for gas in the context of the Energy Security Package, such as the LNG and Storage Strategy have been welcomed by our industry. However to attract new investment in European exploration and production, which along with new sources of gas flexibility such as LNG and pipeline gas, is what helps to underpin security of supply and market competition, the EU should recognise the importance of providing consistent and positive signals to potential investors. In the space of just a few short years, China has quickly entrenched itself as one of the most active foreign energy players on the African continent. This has to do with the search for more secure oil supplies in the face of static if not declining domestic oil production. China’s oil companies are relative latecomers to petroleum exploration and production in Africa. The main difference with Western oil companies is that are primarily driven by profit, and not by their respective country’s national security considerations while the Chinese state oil companies are geared towards the acquisition of oil supplies for the Chinese economy, not the open market. Moreover, Western companies are accountable to their share-holders, Chinese companies are accountable to the state. Western companies are essentially on their own in making investment pitches in African countries. Chinese companies enter a market with the full institutional backing of the state covering financial resources, diplomacy, trade and development projects, and security and intelligence assistance. Yet

China’s current wave of investment in Africa’s oil sector include some of the largest projects on the continent, this despite the crippling world recession. While the collapse in the equity value of corporate shareholdings on the world’s bourses has postponed or halted new investment projects by Western companies, it has heightened China’s predatory instinct to buy-out vulnerable resource rich foreign companies at bargain basement prices to increase its lock on global resources. Sitting on a foreign reserve war chest of over US2 trillion – the largest in the world – China is also able to offer generous aid and loans to African countries, using it as a leverage to win major energy and other contracts. It is evident that if properly executed, the opportunity to invest in exploration in the Continental Shelf of Malta and the linkage to the EU grid of LNG through a gas pipeline to Italy, Malta may become the new Mediterranean Hub. European policymakers, including the European Commission, should reflect further on how to create a policy framework that encourages investment through policy stability and technology neutrality. The industry will need to focus once again on exploration as soon as the commercial environment allows, find new fields and be able to put into production already known marginal accumulations. This is the most taxing challenge.

Author Marilyn Formosa Business & Securities Associate

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The challenges of monetizing and exporting East Med gas to the global markets Key issues that affect global gas markets and challenge monetization and export of East Med gas include: • Global energy markets are undergoing permanent structural change to low-carbon energy • The Paris Climate Agreement is impacting global energy • Trump’s election to the US presidency and US shale oil and shale gas are affecting markets • There is a gas and LNG glut in global markets leading to low gas prices

BP’s Energy Outlook to 2035 The future development of global energy is well covered in BP’s Energy Outlook 2035 published in January 2017. It is in broad agreement with International Energy Agency’s (IEA) forecasts. Its key findings are: • Global energy consumption will rise by 30% between 2015-2035, driven by developing countries, mostly in Asia, but only at 1.3% per year, Fig 1 • Primary energy demand within the OECD economies, such as Europe, will barely grow at all • This is largely due to renewables and increasing energy efficiency offsetting energy demand growth • A permanent energy transition is under way – technological improvements and environmental concerns are changing the primary energy mix towards low carbon, cleaner, energy • Over half the growth in energy consumption will be from non-fossil fuel sources

• But fossil fuels will still account for 75% of primary energy demand even by 2035 • Gas consumption will grow faster than oil and coal, Fig 1, but at a slow rate – with 50% exported as LNG • Renewables will be by far the fastest-growing energy source, quadrupling over the next 20 years BP’s key conclusion is that a major and permanent energy transition is under way. The global energy landscape is changing and the energy mix is shifting to cleaner energy. But forecasts, such as BP’s, are being challenged by the drive to shift global energy permanently to low-carbon sources and

achieve the 2degC goal, enshrined in the Paris Climate Agreement.

Global energy transition The IEA and the International Renewable Energy Agency (IRENA) issued in March 2017 a joint report on global energy transition entitled ‘The Perspectives for the Energy Transition: Investment Needs for a Low-Carbon Energy Transition”. They concluded that achieving the 2degC goal would require energy-related CO2 emissions to peak before 2020 and fall by more than 70% from today’s levels by 2050. The share of fossil fuels in primary energy demand would halve by 2050, while the share of low-carbon sources would more than triple

Fig 1. Global fuel mix transition

Source: BP

worldwide to comprise 70% of energy demand in 2050. The fossil fuel upstream sector carries the main risk for stranded assets as a result of this. The maximum annual decline for oil demand to achieve the 2degC goal would need to be about 3.5% per year, while that of gas would need to be about 2.5% per year. As demand for renewables advance this will create a permanent glut of supplies, with prices expected to remain low forever. This means that the challenge on East Med gas securing export markets can only but increase with time.

Abundance of oil & gas resources There is an abundance of technically recoverable oil resources, totaling 2.6 trillion barrels of oil. According to BP’s Outlook, as a result of the slowing growth of oil demand, less than half, about 1.25 trillion barrels, of these oil resources will be consumed by 2050, Fig 2.

Source: BP

Fig 2. Abundance of hydrocarbon resources

As Sheikh Yamani, ex-Saudi Oil Minister, said in 2003 “The Stone Age did not end for lack of stones, and the Oil Age will end long before the world runs out of oil.” Prophetic! Similar arguments apply to natural gas. IEA’s World Energy Outlook 2015 estimated that, at the end of 2014, total remaining technically recoverable gas resources amounted to at least 781 trillion m3. According to BP’s Outlook, only 155 trillion m3 will be consumed by 2050, leaving the world with a glut of natural gas resources. The world is facing a long-term oil and gas glut. And US shale gas is about to do the same to gas prices as shale oil is doing to oil prices.

The US LNG factor The great success of the US shale revolution is in the production of natural gas. In addition, with shale oil production growth comes more low cost associated gas. Growing US gas production, and a saturated domestic market, are driving increasing gas exports as LNG. US LNG is already having an impact on global prices, contract trends and destination flexibility. As US LNG exports ramp-up, the old models of stable long-term contracts are coming under pressure and are having to change in response to what is becoming a more flexible and liquid market. 24 | MED OIL & GAS | November 2017

Source: Platts

Fig 3. European gas and coal prices, 2016

US LNG export prices will be providing a cap on prices to the Asian markets, much the same way as US shale oil is doing to the global oil market. Cheniere Energy confirms that it has no trouble finding markets for its LNG. In addition, President Trump is supporting US LNG exports. US LNG exports are increasing rapidly, limiting the build-up of unused gas in the US, which in turns encourages more production. By 2020 the US could become the world’s third-largest LNG exporter, behind Australia and Qatar. Coupled with Qatar’s decision to lift its moratorium on further gas production from its

North Dome gas field, the impact of global LNG markets and prices will be substantial.

The Gazprom factor Given the importance of Europe to East Med gas export aspirations, it is important to examine the impact Gazprom has on Europe’s gas demand and supplies in more detail. Gazprom settled its anti-trust case with EU earlier in 2017 by adapting its contracts and approach to be more compatible with EU regulations. BP predicts Gazprom gas supplies to Europe to grow to 40% by 2035. Shell agrees. With Nord Stream 2 as well as Turk Stream 1 and

2 now likely to go ahead, this looks quite possible. Gazprom has 100-150 bcm spare capacity and can produce this on demand at marginal cost. By the time it gets to Europe Gazprom can sell it as low as $3.50 per mmBTU and still make profits. The average gas price in Europe in 2016 was $4.7 per mmBTU, Fig 3. Norway and Algeria, EU’s other main gas suppliers, can neither match this nor have the capacity to export more gas to Europe. And the much-heralded Southern Gas Corridor has problems and limitations. In fact, spare capacity in TAP may be used by Gazprom to take TurkStream gas to Europe. Gazprom has already alluded to that. Nobody else can sell gas to Europe at such prices. Gazprom made it clear that if it needs to, it has the capacity and is prepared to defend its gas markets both in Europe and in Turkey.

Implications on global gas prices Clearly with the fast-changing global energy landscape not all discovered hydrocarbons will be consumed even by 2050. This means that increasingly there will be strong competition between producers to capture this more limited market, with US shale having a major impact. As a result mostly cheaper resources will be able to be developed and compete, mainly in the Middle East, US and Russia. Low-cost producers will use their

competitive advantage to increase their share relative to higher-cost producers – as for example Russia is doing in Europe. More costly resources will find it difficult to compete and increasingly run the risk of remaining stranded, as the world shifts gradually from fossil fuels to renewables. This has been happening since 2014 leading to persistently low oil, gas and coal prices. And this is one of the main reasons prices are very likely to remain low for the longer term. In fact, the average price forecasts of landed LNG over the next 20 years are: • Europe NWE: $5.50/mmBTU • Japan JKM: $7.50/mmBTU East Med gas-field development and production, transport by pipeline to a liquefaction plant, liquefaction and profits will have to be recovered within these prices. Impossible for exports to Europe and challenging for exports to Asia.

East Med export option challenges Egypt and Turkey as potential export markets for East Med gas merit consideration.

ing the next 5 years, in line with expected economic growth. But adoption of renewables, energy efficiency and removal of subsidies, are expected to lower this. Current gas production has already reached 53 bcm/yr. There are 12 projects currently under development, expected to bring an additional 55 to 65 bcm/yr gas on stream by 2020, with more to come later. Even though some of the older gas-fields are fast declining, by 2020 Egypt will have more than enough gas for its own needs and plans to resume LNG exports. In fact, the Paris-based Observatoire Mediterraneen de l’ Energie (OME) forecasts that by 2030 surplus gas in Egypt will exceed 20 bcm/yr, more than enough to fully utlilise its LNG plants at Idku and Damietta.

Turkey Driven by security of supply concerns, as well as costs, Turkey has changed its energy strategy and future energy mix. The emphasis now is on increasing use of lignite and coal, hydro, renewables, nuclear and LNG, and reducing dependence on pipeline gas.

Egypt Egypt expects to become self-sufficient by 2018 – and start gas exports by 2021.

In addition, Turk Stream and TANAP will be brining more gas to Turkey by 2018/2019

Gas demand is close to 60 bcm/yr. The IEA expects it to increase by 4-5% per year dur-

The average price of Russian and Azerbaijan gas to Turkey at the end of 2016 was just about $5 per mmBTU. East Med gas needs to compete and beat such prices if it is to succeed selling to Turkey, for which the origin of gas molecules does not matter – only price does.

Pipelines East Med gas pipeline export options are, Fig 4: • EastMed: Israel-Cyprus-GreeceEurope gas pipeline • Israel to Turkey gas pipeline • Gas exports to Egypt What makes these options commercially challenging is that, for gas at the platform, it is difficult for Noble Energy to charge international clients less than the minimum price of gas in the Israeli domestic market, currently at $4.70 per mmBTU.

Fig 4. East Med gas pipeline export options

Source: Bloomberg

The EastMed pipeline is considered to be a strategic project for exporting East Med 25

gas, and in particular Israeli gas. The aim is to create a direct gas export route from the region to Europe by 2025. A pre-FEED study was completed recently by IGI-Poseidon, a joint-venture between Italy’s Edison and Greece’s DEPA, and funded by the European Commission. The study has claimed the pipeline is technically and commercially viable – but is did not disclose at what gas price.

price would be too high to find buyers there. Last year’s average price of Russian gas to Turkey was about $5 per mmBTU, a price which Israeli gas cannot match. In any case Turkey made it clear that the key factor for any gas imports is price. Gas from Israel to Turkey and then Europe faces similar commercial challenges as the EastMed gas pipeline, making it not viable.

The way forward - LNG and FLNG In fact the pipeline can become commercially viable only if the price of gas in Europe exceeds $7-8 per million BTU – highly unlikely. In addition to the political problems of having to cross Cyprus EEZ, by the time an Israeli gas pipeline reaches Turkey, given the likely price at the Leviathan platform, the

Cyprus and Israel lack gas export infrastructure. They are also fast running-out of export options. That’s why LNG and FLNG are coming back into the equation. Provided substantial quantities of gas are discovered, LNG may be the main option to

Well Operations Crew Resource Management

export East Med gas to the global markets. FLNG is also possible and can avoid regional geopolitics. It creates new opportunities for producing countries by unlocking access to isolated gas reserves which are not cost-effective for development by other means. It was considered previously by Noble for the development of Tamar first and later as an option for Leviathan. Costs vary, but a comparable project is ENI’s Coral FLNG in Mozambique, which reached FID in June 2017. Lying in about 2000m water depth, with 5tcf gas, it has similarities to Aphrodite gas-field and most of Cyprus EEZ. Given that Coral’s LNG has already been bought by BP for the Asian markets, the price must be competitive in the present environment. FLNG could be the game-changer in the development of East Med gas resources in a financially viable manner.

The future Gas discoveries in the East Med are deep-water and expensive to develop. They are also far from the likely markets in Asia. With more gas discoveries, a grand-collaboration among all players in Cyprus EEZ would indeed be the best in terms of minimizing development costs and improving chances to secure exports. A single project including all Cyprus’ gasfields, known and to be discovered, developed through subsea completions and pipeline tie-ups to new liquefaction trains to be built in Egypt’s existing LNG plants may be the way forward. Cyprus’ dream to build a greenfield LNG plant at Vasilikos may be an option, but it is challenged by lack of infrastructure and consequently high development costs.

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In a low price environment, only integrated projects which minimize costs from wellhead-to-export will stand a chance to become financially viable and secure export markets. And even then it will be challenging.

Author Dr. Charles Ellinas CEO E-C Natural Hydrocarbons Company Ltd

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Through non-intrusive inspection, Tracerco’s range of Asset Integrity services can allow you to: • Save up to 1/3 on the cost of pipeline inspection campaigns • Obtain results online and in real time • Inspect any complex pipeline system including pipe-in-pipe, pipe bundles, unpiggable pipelines, risers and jumpers, to obtain accurate wall thickness measurements without removing the protective coating • Quickly and reliably survey platform members (typically 100 members per 12 hour shift) to determine the degree of water ingress • Safely and accurately track pipeline pigs

Inspecting Unpiggable Pipe Systems – Integrity, Flow and Pipe Movement Inspections TM with Discovery As an increasingly large number of conventionally “unpiggable” and difficult to inspect pipeline systems approach the end of their design life, and with these pipelines often being used in challenging environments and in harsh service operations, new techniques are needed to ensure that these pipelines are safely able to continue operating. This is particularly important considering the continued financial pressures being faced by the oil and gas industry. Introduction Fig 1: Discovery™ CT scanner

Discovery™ is the world’s first subsea Computed Tomography (CT) scanner. It is a non-intrusive external scanning technique which does not affect the operation of the pipe. It also does not require removal of any external coating applied to the pipe, being equally adept at scanning through 50mm of heavy concrete weight coats as it is at scanning through micron-thick fusion bonded epoxy coatings. CT scanners are particularly suited for scanning pipelines that, for various reasons, may be difficult to inspect by conventional techniques, such as in-line inspection or local inspections such as UT or PEC. Reasons a pipeline may be considered difficult to inspect or unpiggable include: • No pig traps installed or pig traps removed • Multi-diameter pipes • Tight bends in the line, particularly those associated with smaller diameter pipes • Pipe cleanliness - deposit or build up inside the pipe bore which may not 29

• • •

Piggyback Pipe Systems

be controlled by any existing applied inhibition mechanisms Internal coatings or linings External coatings Additional metal items such as heating elements, centralizers or piggyback pipe supports Low or even no flow rate Dead legs Pipe-in-pipe or multi-pipe systems

In these situations, an operator may be forced to simply “manage” their pipeline with assessments and models which, while useful, are limited by the information they are built on. In turn, this can lead to over-conservative approaches which could prematurely “fail” a perfectly acceptable pipeline. This is a particular concern for pipelines approaching the end of their design lives and where information pertaining to their historic operation may be unreliable or unavailable.

Computed Tomography (CT) and Discovery™ Discovery™ operates along the same basic principles as CT scanners used in hospitals worldwide, with the main difference being the type of source used. For medical CT an x-ray source is used, whilst for DiscoveryTM a gamma ray source is used. The reason is that the gamma ray’s high energy photon beam can pass through denser materials such as steel, whilst an X-ray CT beam is lower energy and less ionizing (and therefore safer for the person being scanned) but the lower energy means it cannot even pass through bone. The principle behind Discovery™ (and CT scanning) is relatively simple – the CT beam passes through a material and the density of this material can then be calculated by

Whilst piggyback pipe systems provide many bennefits to an operator (a single pipeline route being just one example), inspecting piggyback pipe systems has previously provided a particular challenge as the narrow spacing between the pipes makes it difficult for traditional techniques to perform a full 360 degree scan.

Fig 2: Two of the Many Possible Solutions to a Simple Killer Sudoku Puzzle

how much the beam is weakened (the attenuation coefficient). Reconstruction models then take this information and use it to generate an accurate image of the scanned item. CT reconstruction models are easiest understood by considering them as being like Killer Sudoku puzzles, so loved by commuters worldwide. In Killer Sudoku, you have a grid with values at the end and from this you have to work out what sum gives the correct answer (Figure 2). Now, whilst a 9 x 9 Killer Sudoku grid is a normal (if tough) challenge for a daily commute, for industrial CT scanners the grid is many times larger. Consequently, it is only possible to “solve” a CT scan by the use of computers and iterative algorithms.

Selected Projects The IEA and the International Renewable With Discovery™ now having performed over 500 scans on pipelines, flowlines and risers in the Gulf of Mexico, and a similar number across the various North Sea sectors, Discovery™ has proven itself across a wide variety of pipe systems, highlights of which include:

Unlike traditional inspection methods which need full access to all areas of the piggyback pipe, using specially designed external spacers, Discovery™ clamps around the outside and in one single scan performs a full scan of both of the piggyback pipes (Figure 3). In Figure 3, both the main production pipeline and smaller piggybacked support line are clearly visible at all positions and orientations. This means that wall thickness and flow measurements can be taken and assessments can be performed. The bolts and pins securing the two halves of the specially designed pipe clamp can also be seen around the outside of the scan field, as can the ties used to separate the upper and lower pipes.

Pipe-in-Pipe Systems and Pipe Bundles Pipe-in-pipe systems and pipe bundles are particularly difficult to inspect by traditional methods for many reasons, including: • Can’t visually inspect the inner pipes from outside • Not possible to inspect the outer pipe from inside (due to annulus) • Inner pipes may be lined or manufactured from a corrosion resistant alloy (CRA) • Centralizers or spacers – extra (irregular) material inside the pipe • Heating elements or insulation Pipe-in-pipe systems are also ideal for use in challenging environments or for transporting products where a high temperature needs to be maintained, as they provide the highest level of insulation since the annulus allows for an area where a low conductivity material (such as air, nitrogen or aerogels) can be contained. Whilst it would be possible to produce a single pipe with sufficient external insulation coating to maintain temperature, the amount of insulation required makes it impractical.

Fig 3: Piggyback Pipe Inspection

30 | MED OIL & GAS | November 2017

Fig 4: Pipe-in-Pipe Inspection with Selected Wall Thickness and Spacing Measurements

Discovery™ has proven itself to be particularly adept at scanning pipe-in-pipe systems (Figure 4), providing accurate wall

Fig 5: Pipe-in-Pipe Inspection Showing Extreme Movement of Inner Pipe

Fig 6: Pipe-Bundle Inspection with Selected Features Highlighted

Fig 7: Concrete Weight Coated Pipe Inspection

thickness measurements for both inner and outer pipes as well as being able to provide a report on the condition of the spacing between the inner pipes. A test-tank example of extreme pipe movement of the inner pipe with respect to the outer pipe, as has been seen now in several Discovery™ scans, is provided in Figure 5.

ing the safety of the pipeline. As can be seen in Figure 7, Discovery™ was clearly able to identify (to the standard tolerance) the pipe wall thickness and areas of wall thickness reduction, the seam weld and pipeline ovality. In addition, Discovery™ could clearly identify the positions of the concrete rebar and supporting metalwork.

With pipe bundles being, at least to Discovery™, the same as pipe-in-pipe systems, pipe bundles present only a similar level of complexity. Figure 6 shows a test-tank scan of a pipe bundle where the various pipelines, umbilicals and even seam weld and rust accumulation in the bottom of the pipeline can clearly be seen.

Build-Up and Blockages

bore blockages and damage, either because of continued product precipitation or due to chunks of deposit being transported along the line. The end result is an increase in production costs and a restriction in the operational capacities of the line. On some lines, high product temperatures need to be maintained in order to inhibit wax and hydrate formation to minimize the risk of blockages and the need for more invasive remediation strategies.

Concrete Weight Coated Pipes Historically, to perform a conventional inspection campaign on an unpiggable concrete weight coated pipe, most inspection techniques would require the operator to remove the concrete weight coating on the pipe. There are several issues with this approach, including:

Wax and hydrate are two common flow assurance threats when transporting unprocessed hydrocarbons. Both can precipitate out of the transported product and deposit onto the line. Initially this decreases the pipeline’s cross-sectional area and reduces the volume of fluid able to be transported at a time whilst at the same time increasing production costs as more power is required to propel the fluid along the pipeline (Figure 8). Eventually this can cause complete pipe

Maintaining the temperature also reduces the risk of under-deposit corrosion – a corrosion mechanism of concern to many Operators as maintaining sufficient product temperature can be difficult. Under-deposit corrosion is a localised corrosion mechanism that tends to be very aggressive and is difficult to control by inhibitors as they cannot reach the corroding metal due to the pres-

• Accidental damage during or after concrete weight coating removal • Potential exposure of external pipe surface to corrosive environment • Reduced production whilst concrete removal occurs • Repair of concrete weight coating once scanning complete • Increased inspection time and cost Discovery™ scans through the concrete weight coating, reducing the time and cost of the inspection campaign without reduc-

Fig 8: Hydrate Formation and Remediation Loop – Real Time Monitoring with Discovery™ 31

ence of the deposit layer. DiscoveryTM scans can be performed on operational lines, enabling an operator to see the actual fluid flow conditions during the pipes normal operation and quickly and easily identify any areas of water hold-up, deposits or any other flow-associated issue. To quote one Senior Pipeline Engineer “In just one ten-minute scan, DiscoveryTM has shown me more about the condition of this pipeline than I have obtained from all of my modelling over the last two years”. As can be seen in Figure 8, DiscoveryTM was successfully able to identify all the hydrate formation and dissociation steps and accurately identify the actual product pressure to within 0.1g/cm3. This provided an Operator with the data necessary to implement the most suitable remediation strategy to resolve the issue, improving productivity and reducing costs – whilst at the same time

reducing the environmental impact of the process.

Conclusions By using DiscoveryTM, Operators can now inspect traditionally “unpiggable” and difficult to inspect lines and “see” inside operational pipelines to a higher degree than has previously been available – all without interrupting production and therefore differing revenue. In a single scan, DiscoveryTM generates data for wall thickness (integrity) assessments as well as providing accurate measurements of flow profile and product density. Since this can be done on a fully operational pipeline, DiscoveryTM allows an operator to confirm and monitor that flow assurance and remediation strategies are working, as well as ensuring that corrosion and inhibition strategies are effective and suitable.

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Since DiscoveryTM entered the market in 2015, over 500 scans have been performed – allowing Operators to save on inspection programs, safely extend the operational life of their lines, as well as maximise productivity.

Authors Jennifer Briddon Integrity Engineer, Tracerco Michael Jefferson Discovery Technician, Tracerco

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Oil Special Quarterly Report Moderate oversupply and range-bound/bearish outlook for $50 Brent in 2018

N OT I CE IMPORTANT NOTICE The circumstances in which this publication has been produced are such that it is not appropriate to characterise it as independent investment research as referred to in MiFID and that it should be treated as a marketing communication even if it contains a research recommendation. This publication is also not subject to any prohibition on dealing ahead of the dissemination of investment research. However, SG is required to have policies to manage the conflicts which may arise in the production of its research, including preventing dealing ahead of investment research.

• Summary: Our fundamental outlook has become weaker, with moderate global stockbuilds now expected next year. As a result, our crude price outlook is broadly range-bound. We are bearish with respect to current frontmonth prices and forward curves. • Price forecasts – ICE Brent: We forecast front-month ICE Brent prices at $50.00 in 4Q17, $51.50 in 1Q18, $48.50 in 2Q18, and $51.50 in 3Q18. Based on normal $10-wide trading ranges, we expect Brent to trade in a $43.50$56.50 range over the next 12 months. On an annual basis, we forecast Brent at $51.55 for 2017 and $50.00 for 2018. • Price forecasts – NYMEX WTI: For front-month NYMEX WTI prices, we forecast $47.50 in 4Q17, $49.00 in 1Q18, $46.00 in 2Q18, and $49.00 in 3Q18. Based on normal $10-wide trading ranges, we expect WTI to trade in a $41-$54 range over the next 12 months. On an annual basis, we forecast WTI at $48.80 for 2017 and $47.50 for 2018. 34 | MED OIL & GAS | November 2017

• Upside and downside risks: OPEC poses the biggest risks. It could “double down” with a new cut (30% probability), which would be very bullish (+$10). It could also “throw in the towel” and abandon cuts (10% probability), which would be very bearish (-$10). • Non-OPEC supply: For non-OPEC output plus OPEC NGLs, we project gains of 1.0 Mb/d in 2017 and 1.6 Mb/d in 2018, led mainly by the US but with notable growth also from Canada, Kazakhstan, and Brazil. We forecast growth in total US liquids production, including crude and NGLs, of 0.75 Mb/d in 2017 and 1.15 Mb/d in 2018, driven by shale oil and NGLs. • OPEC crude supply: We expect OPEC to maintain current production targets steady through 2018; we also project actual output flat at recent levels of 32.8 Mb/d through 2018. This would result in OPEC increasing crude output by 0.3 Mb/d next year, following a cut of 0.3 Mb/d this year. Much of OPEC’s 2017 cuts have been offset by gains in Libya and Nigeria. • Demand: We expect global oil demand to remain healthy, and project growth of 1.6 Mb/d in both 2017 and 2018. This should be driven by emerging markets, including China, India, and other emerging Asia. We also expect significant growth from the US. • Inventories: Putting ample supply together with healthy demand, the result is a balanced global market in 2017, but a moderately oversupplied market in 2018, by 0.3 Mb/d. This is the critical element behind our rangebound/bearish crude price outlook. • Note: This Oil Special is adapted from the quarterly Commodities Outlook titled “A Commodity Cacophony”, published on Monday 11 September 2017.

The Commodities Outlook contains the full set of short-term and long-term price forecasts for crude oil and refined products by region, as well as trading recommendations for oil.

Price forecasts – Short-term crude oil through 2018 Our fundamental outlook through 2018 has become weaker, with moderate global stockbuilds now projected for the year as a whole. As a result, our price outlook has been revised lower compared to our previous price forecast, which was dated 29 June 2017. We are bearish with respect to current front-month prices and current forward curves. Our forecast calls for broadly rangebound crude prices. We expect crude and product stockdraws and stockbuilds in line with normal seasonality, which means that we anticipate a tactical market. We forecast front-month ICE Brent prices at $50.00 in 4Q17, $51.50 in 1Q18, $48.50 in 2Q18, and $51.50 in 3Q18. Based on normal $10-wide trading ranges (see below), we expect Brent to trade in a $43.50-$56.50 range over the next 12 months. On an annual basis, we forecast Brent at $51.55 for 2017 and $50.00 for 2018. We project that going forward, NYMEX WTI will trade at an average discount of $2.50 to ICE Brent. This discount, which is likely to remain volatile, should – on balance – incentivise US crude exports, which should continue to an increase in line with growing US crude production. As such, we forecast front-month NYMEX WTI prices at $47.50 in 4Q17, $49.00 in 1Q18, $46.00 in 2Q18, and $49.00 in 3Q18. Based on normal $10-wide trading ranges, we expect WTI to trade in a $41-$54 range over the next 12 months. On an annual basis, we forecast WTI at $48.80 for 2017 and $47.50 for 2018. Our base-case crude price forecasts should be considered as the centre points of normal $10-wide trading ranges; in other words,

crude prices may routinely trade $5.00 above or below our forecasts, based on normal volatility, driven by seasonally changing fundamentals, non-fundamental factors and geopolitical developments. Looking at front-month vs 1-year forward timespreads for ICE Brent, we expect relative strength during periods of peak refinery crude demand, in the winter (1Q18) and the summer (3Q18). As discussed below in the inventories section, during these periods of relative strength, the contango should decrease. Brief periods of backwardation are possible, but we do not believe they will be sustainable. If our most extreme upside price risk were to materialise – OPEC “doubles down” on supply management and implements a large new cut of 1 Mb/d – we would expect to see crude prices $10 higher than our base case and be in a $60 world, rather than a $50 world. If our most extreme downside price risk were to materialise – OPEC

“throws in the towel” and abandons supply management – we would expect to see crude prices $10 lower than our base case and be in a $40 world, rather than a $50 world. See upside and downside price risks sections below.

Price forecasts – Short-term refined products through 2018 Regarding the outlook for product cracks and refining margins in the US, Europe and Asia, we project a slightly weaker but still broadly range-bound environment in 2018 relative to 2017. There continues to be ample spare refining capacity in the world, and global product demand growth remains healthy, led by light ends, gasoline, and distillate. Therefore, the big picture for refined products has not changed since our last quarterly report. It is worth noting that Hurricane Harvey, which struck the US Gulf Coast in late August, has had a very visible impact in boosting cracks and margins in August-Septem-

World crude oil benchmarks ($/bbl)

ber 2017, 3Q17, and 2017 as a whole. This contributes to the slight decline we forecast for next year relative to this year. The storm caused the shutdown of 4-5 Mb/d of refining capacity at the peak, leading to sharp spikes in gasoline and distillate cracks, not just in the US, but in Europe and Asia as well. The recovery in the US oil sector has begun and refining capacity is starting to come back on line. The market impact, which was bearish for crude (much lower refinery crude demand), as well as bullish for products, has already begun to fade. At this point, we expect US and global product cracks and refining margins to normalise by the end of September, though this assumption is of course subject to change. Readers should note that we have analysed the impact of Harvey in detail in our weekly US Petroleum Report, and this will continue in the weeks ahead. Our full set of detailed regional refined product price forecasts is included in the tables at the front of this report. Focusing

ICE Brent and NYMEX WTI 1st NB – 13th NB spreads ($/bbl)

Source: Bloomberg, SG Cross Asset Research/Commodities

ICE Brent short-term forecasts vs forward ($/bbl)

ICE Brent long-term forecasts vs forward ($/bbl)

Source: SG Cross Asset Research/Commodities

on proxies for refining margins in the US, we expect 3-2-1 cracks vs LLS to drop from $16.90 in 3Q17 to $11.35 in 4Q17, but to recover to $13.35 in 1Q18. We forecast the 3-2-1 cracks at $13.15 for 2018 vs $14.15 for this year. The NYMEX RBOB and ULSD cracks should both ease next year, on an annual average basis. In Europe, our forecasts are for 5-2-2-1 cracks vs Brent to drop from $9.20 in 3Q17 to $6.80 in 4Q17 and $6.60 in 1Q18. We forecast 5-2-2-1 cracks at $7.30 for 2018 vs $7.45 for this year. The ICE Gasoil crack should also ease next year, on an annual average basis.

Price forecasts – Long-term crude oil 2019-2022 We have revised down our long-term price outlook, as well as our short-term forecast. The main theme is straightforward but powerful. We believe that as is the case for 2018, US shale oil supply growth will continue to be the biggest single contributor to meeting global demand growth in 2019 and 2020. As such, the marginal production cost of US shale oil, including a healthy profit margin/ rate of return, will continue to anchor the forward curve. It should also be noted that we assume that shale oil production costs will be gradually increasing in the coming years. Our outlook calls for ICE Brent to increase from $50 in 2018, to $55 in both 2019 and 2020, $60 in 2021, and $65 in 2022. For 2019 to 2022, these represent downward revisions of -$2.50 in each year compared to the previous forecast. The overall upward path is based on the eventual need for high-cost crude from

deepwater offshore and Canadian oil sands. However, the volumes of high-cost crude required appear to be coming down. Moreover, and perhaps more importantly, deepwater offshore costs are declining and the majority of Canadian oil sands growth at this point is coming from lower cost in-situ development (SAGD). To the extent oil sands growth is coming from higher-cost oil sands mining projects, the producers are focusing mainly on cheaper expansions of existing projects, rather than more expensive new greenfield projects. The underlying reason for the eventual need for high-cost crude is that by 2021 and 2022, we still expect to see some impact from the exploration and development spending cuts in non-OPEC excluding the US that have taken place in recent years. On the demand side, in our base case, we factor in a key assumption from our macro team that beginning in 2019 and extending into 2020, there will be a global economic slowdown, driven by the advanced economies. This is forecast to be significant enough to impact emerging economies, the key driver of oil demand. As a result, oil demand growth and therefore oil prices will suffer. This causes the gradual increase in our forecast price profile to stall out in 2020, with increases resuming in 2021 and 2022.

Supply – Non-OPEC: strong growth, led by the US On the supply side, which has dominated the fundamental discussions in the oil markets for most of the year, we forecast growth in annual non-OPEC output plus OPEC NGLs (in other words, all global supply excluding

Non-OPEC supply growth by region, 2016-2018 (yoy)

Source: History – IEA; forecast - SG Cross Asset Research/Commodities

36 | MED OIL & GAS | November 2017

OPEC crude) of 1.00 Mb/d in 2017 and 1.58 Mb/d in 2018 (see chart below left). By region, growth is being dominated by North America (which we expect to grow by +0.79 Mb/d in 2017/+1.21 Mb/d in 2018). In addition, there are also notable contributions from the FSU (SG: +0.14 Mb/d/+0.05 Mb/d) and Latin America (SG: +0.11 Mb/d/+0.16 Mb/d). By country, gains are being led by the US (shale oil), Canada (oil sands), Kazakhstan (Kashagan), and Brazil (several deepwater sub-salt fields). US production continues to be the most important driver for non-OPEC supply as a whole. We forecast growth in US crude output, which bottomed out in 3Q16, of 445 kb/d in 2017 and 690 kb/d in 2018 (see chart above right). On a quarterly basis, our forecast for growth in US crude supply is 830 kb/d yoy in 4Q17; this continues to be a key metric in the market. In addition to crude growth, NGLs output should increase by 300 kb/d in 2017 and 460 kb/d in 2018, on our forecasts; this would bring total US liquids growth to 745 kb/d in 2017 and 1.15 Mb/d in 2018. Looking at the regional details for US crude, we project onshore Lower 48, which mainly consists of shale oil, to grow by 350 kb/d in 2017 and 550 kb/d in 2018. We expect output in the Gulf of Mexico to grow by 105 kb/d this year and 145 kb/d next year. All-important US shale oil growth, which is considered the main source of marginal crude supply in the world through 2020, is being driven this year by capital spending increases of more than 40%, combined with

US crude production growth by region, 2015-2018 (yoy)

Source: History – US EIA; forecast - SG Cross Asset Research/Commodities

OPEC crude production 2015-2017

Source: IEA, Reuters, SG Cross Asset Research/Commodities

full-cycle production costs that are down 35% from late 2014 to early 2017; in absolute terms, representative shale costs have fallen from $60-65 to $40 over that time frame, with Permian costs lower at $35. We continue to see increases in drilled but uncompleted wells in the shale regions. Wells are being drilled faster than they can be fracked and completed. As discussed on other occasions, the availability of fracking and completion crews continues to be a constraint for the shale sector. In addition, the availability of pressure pumping equipment is tight, and the same can be said for sand, a key material needed for fracking and completion.

Supply – OPEC: we expect both current targets and actual output to remain flat through 2018 Total OPEC crude output averaged 32.8 Mb/d in June-August, including Libya and Nigeria, which are not part of the agreement to cut output. This represents a cut of only 0.6 Mb/d vs 4Q16 output of 33.4 Mb/d (see chart below left). For the countries that are cutting, compliance has dropped from near 100% in January-May to 70-80% in June-August. That said, as shown in the chart below right, our view is that OPEC is still doing a pretty good job of maintaining the cuts, and in any case, 70-80% compliance is in the historical range of previous agreements. The issue for OPEC is not compliance, it is Libya and Nigeria. Total OPEC output in July was 960 kb/d higher than March, and Libya and Nigeria accounted for 70% of the increase. In our base-case supply forecasts, we expect OPEC to maintain current pro-

OPEC crude production 2016-2017 – Focus on Nigeria & Libya

Source: IEA, Reuters, SG Cross Asset Research/Commodities

duction targets steady through all of 2018, and we project actual output flat at 32.8 Mb/d through all of 2018. Indeed, recent public comments from OPEC members indicate that further extensions of the current agreement beyond March 2018 are already being considered. While the next OPEC meeting is not until late November, it is already worth considering some tough decisions that the members may have to make. We see three basic possibilities. • Maintain status quo (60% probability). This is our base case, and results in moderately oversupplied markets and $50 Brent next year. There is no rebalancing or sustained stockdraws. Inertia makes this the easiest and most likely option, given that it took almost a full year in 2016 to come up with a convincing output cut agreement that included detailed country-by-country production targets. It is possible that OPEC tries to bring Nigeria and Libya into the agreement. Nigeria has said it would consider this when it reaches 1.8 Mb/d of crude output for three months; it is still more than 100 kb/d from this level. Libya has been less positive; it reached 1.0 Mb/d recently, but has said its target is 1.25 Mb/d (we are sceptical). In any case, while bringing Nigeria and Libya into the agreement would be positive for sentiment, it would merely affirm the status quo in terms of crude production. • “Double down” with a new large output cut (30% probability). A new cut of 1 Mb/d would probably be required. 0.5 Mb/d would not be enough be-

cause the resulting price increase could well result in incrementally higher US production growth of 0.5 Mb/d (after a time lag), therefore offsetting the cut. In contrast, we see US shale growth having difficulty in offsetting a 1 Mb/d OPEC cut; i.e. with US shale expected to grow by 0.7 Mb/d next year in the base case, we don’t think it can grow by 1.7 Mb/d to offset OPEC. As a result, this scenario results in a $60 Brent world, rather than $50. • “Throw in the towel”, abandon output cuts, and return to the 2014 market share strategy (10% probability). While from a purely petroleum economics perspective, this is probably the most effective long-term strategy to lower prices, significantly slow growth in US shale, and regain market share, we give this a very low chance of actually happening. Saudi Arabia’s Crown Prince MBS would effectively be admitting failure in his oil strategy and also in his Vision 2030 plan to diversify the Saudi economy. It would also reduce the financial gains from the planned late-2018 partial IPO of the Saudi state oil company. This low-probability scenario results in a $40 Brent world, rather than $50. In our view, the chances of “throw in the towel” will increase after the partial IPO and after MBS succeeds his father as King.

Demand: Healthy global growth, driven by emerging Asia, with a significant contribution from the US Against a backdrop of continued solid macroeconomic growth, global product demand continues to be healthy; we forecast growth 37

Global product demand growth by region, 2016-2018 (yoy)

Source: History â&#x20AC;&#x201C; IEA, forecast - SG Cross Asset Research/Commodities

at 1.58 Mb/d in 2017 and 1.61 Mb/d in 2018. Global growth should be driven, as usual, by emerging markets (see chart below left). We project non-OECD growth at 1.21 Mb/d in 2017 and 1.36 Mb/d in 2018. We expect China to contribute 540 kb/d in 2017 and 420 kb/d in 2018. Gains should be driven by gasoline, jet fuel, and hydrocarbon gas liquids, including propane used in propane dehydrogenation plants. Other emerging Asia contributes 410 kb/d of growth in 2017 and 540 kb/d in 2018, on our estimates, with India responsible for 130 kb/d and 280 kb/d, respectively. In India, gains should result from transportation fuels, naphtha and ethane feedstock for petrochemicals, and propane for residential consumption. The Indian government currency demonetisation programme in late 2016 caused a decline in Indian demand in 1Q17; however, growth resumed in 2Q17. This factor contributes to the overall slower rate of growth in 2017, and the relatively faster pace we expect in 2018. We also expect OECD demand to grow by 360 kb/d in 2017 and 250 kb/d in 2018, driven by US gains of 300 kb/d and 290 kb/d, respectively. Based on actual demand figures for the first six months of the year, we have revised up our US demand forecasts significantly. Growth is being driven by hydrocarbon gas liquids and distillate. HGL gains are being caused by an increase in ethylene-producing petrochemical plants that use ethane as a feedstock. T wo new plants came on line in early 2017, and five more are expected to start up by 38 | MED OIL & GAS | November 2017

US total product demand, 2015-2017

Source: US EIA, SG Cross Asset Research/Commodities

the end of next year. Distillate demand growth is being underpinned by gains in road diesel, diesel used for oil and gas drilling activity, and industrial fuel uses; these more than offset a decrease in home heating-oil consumption, with part of that being due to a warmer-than-normal winter in 1Q17. A final note on global demand: compared to our last published supply and demand balances from 30 July, weâ&#x20AC;&#x2122;ve revised up global growth from 1.4 Mb/d in 2017 and 2018 to 1.6 Mb/d in both years. However, this is more than offset by a 0.4 Mb/d downward adjustment made by the IEA (the source of our historical data) to baseline absolute demand levels for 2016; the revisions were due to new statistics for non-OECD countries. These adjustments are implicit in our weaker fundamental outlook for this year and next.

Seasonality: Strength in 1Q and 3Q, weakness in 2Q and 4Q As we discussed in our Oil Drivers reports in July and August, we are particularly cautious about prices in the global crude oil and refined product complex in September and October, when the seasonality of crude and product demand turns bearish. All year long, the main focus of the market has been on the supply side, specifically the theme of bullish OPEC output cuts vs the bearish recoveries in production from the US, Libya, and Nigeria. However, over the summer, the markets also increasingly recognised that product demand has been healthy, driving strong refining margins and, in turn, strong refinery crude runs (i.e. crude

demand). That said, there are clear and strong seasonal demand patterns for crude and products. Refinery crude runs peak in the summer (3Q) and winter (1Q), and weaken in the autumn (4Q) and spring (2Q), when planned refinery maintenance is scheduled. The chart below shows the current outlook for global refinery crude runs, with a 1.6 Mb/d drop expected over the two-month period between August and October. Refined product demand also peaks during the summer driving season, which increases gasoline and road diesel consumption, and the winter heating season, which increases heating fuel consumption; these fuels include heating oil in the US Northeast and in parts of Europe, such as Germany, but also include jet/kerosene which is used for heating in Japan and some other parts of Asia. As discussed above, we are expecting a broadly range-bound market through 2018. This means that seasonality will perhaps be more visible than it has been in the last couple of years, when large swings in crude prices tended to dominate the markets. There will be crude and product stockdraws and stockbuilds in line with seasonality. In this tactical market, we expect relative weakness in 4Q17, 2Q18, and 4Q18, and relative strength in 1Q18 and 3Q18. This holds for the crude flat price, crude timespreads, and cracks for key products, such as gasoline and distillate. The markets have been complicated by Hurricane Harvey; as noted above, the initial reaction was bearish crude and bullish

products, and this is now in the process of reversing. However, as we progress through September and October, we expect renewed downward pressure on crude flat price and timespreads. We also expect gasoline cracks, including NYMEX RBOB, to continue to weaken. November is a transition month to winter, and we would expect to see some signs of upward pressure on crude by late in the month, and continuing through February-March. On the product side, we would also expect some upward pressure on distillate cracks, including ICE Gasoil and NYMEX ULSD, to begin in November and also continue through February-March. The winter weather and associated heating demand will, as always, be a big seasonal wildcard.

Inventories: Balanced in 2017 and a moderate build in 2018 Putting the pieces of supply and demand together, our fundamental outlook for the oil markets has become weaker. Following an estimated global implied stockbuild of 0.2 Mb/d in 3Q17, we now forecast global stocks as flat/balanced in 4Q17, with a large build of 0.8 Mb/d in 1Q18. For 2017 as a whole, we forecast globally balanced markets, while we expect 2018 to show a moderate but noticeable 0.3 Mb/d global stockbuild. For OECD stocks, which have timely and accurate reporting, and therefore drive the global markets, we forecast balanced supply and demand in 2017, followed by a moderate 0.1 Mb/d draw in 2018. This is shown in the chart below left; the 2018 picture looks similar to 2017, though days forward cover is slightly lower. Our crude and product price forecasts reflect the “big picture” of moderate 0.3

Global refinery runs should drop 1.6 Mb/d from August to October

Source: IEA, SG Cross Asset Research/Commodities

Mb/d global oversupply in 2018. Rather than going up and down in strict accordance with quarterly stock changes, our quarterly price changes instead reflect the typical seasonality discussed above (stronger 1Q and 3Q, weaker 2Q and 4Q). The dynamics of price formation that we envision through 2018 are similar to what we’ve observed in recent months. There are several key aspects of this, including inventories. First, longer-dated prices for WTI should remain anchored around $50, which is the marginal cost of US shale production, including a healthy profit margin/rate of return (overall shale breakeven costs are currently estimated around $40, though significantly lower in the Permian Basin at around $35). The markets know that $50 WTI a year or two ahead is the key level that has prompted producer hedging activity over the last

OECD crude and product stocks – days forward cover

Source: History – IEA, forecast - SG Cross Asset Research/Commodities

couple of quarters; this is clearly the price level that producers want. Second, the continued oversupply indicated by our inventory forecast should broadly weigh on the front of the crude forward curves, generally keeping markets in contango (front-month vs 1-year forward). Third, the pace of seasonal inventory stockbuilds and stockdraws should exert upward and downward pressure on the front of the crude forward curves. Investor flows should also follow the fundamentals and add momentum to price swings at the front. Producer hedging should weigh on longer-dated prices and dampen any uplift. The chart below right (OECD days forward cover vs ICE Brent timespreads) illustrates that historically, in an OPEC “supply management” market, when days forward cover falls to 2 days above the 5-year average, 1-year timespreads flip into backwardation

(OECD days forward cover vs 5y av) vs ICE Brent 1-yr forward timespreads

Source: Bloomberg, IEA, SG Cross Asset Research/Commodities

(see black circles for Jan. 2008-Oct. 2014). Our forecasts show that stocks do fall just below this level in 3Q17 and 4Q17. While brief periods of backwardation are possible, we are cautious about forecasting sustainable backwardation, for several reasons. First, days cover only drops to around 1.5-1.6 days above the 5-year average – not much below the key 2-days level. Second, sustained backwardation would require the historical statistical relationship between stocks and timespreads to re-assert itself. As shown on the chart, the old “supply management” relationship has not been re-established yet (see blue squares for Nov. 2014-June 2017 and red circles from Dec. 2016-June 2017, after OPEC re-established a supply target). We are simply not sure that it will happen. Before, supply adjustments were only about OPEC. Now, supply adjustments are about both OPEC and US shale. The world is not as simple as it was before.

Upside risks • Stronger economic and oil demand growth than we expect. Any of the bullish risk factors in the SG macroeconomics “swan chart” could prompt faster oil demand growth. This could be worth $5 of upside for crude prices. • Weather-related disruptions. In the middle of an active hurricane season, which peaks in August-October, we note that crude production losses can provide $2.50-5.00 of uplift for crude prices, depending on the lost volumes, and if the crude output losses are significantly larger than any related refinery crude demand and product output losses. This scenario is bullish for crude and bearish for products. − The weather category also includes crude output losses due to heat and drought (such as last year’s Alberta wildfires), winter North Sea storms, and unusual cold/freezing weather in places such as Russia, Canada, and North Dakota.

• Geopolitical risks. Upside geopolitical risks are related to the reality or threat of supply disruptions. Examples include: − US oil trade sanctions on Venezuela, with a ban on US light crude and refined product exports to Venezuela worth $0-1.50 of upside and a ban on US crude imports from Venezuela worth $2.50-5.00 of upside for up to two months, until trade flows adjust; − disruptions once again increasing in Libya and Nigeria; with flows in both countries within 100-200 kb/d of sustainable maximum levels of 1.0 Mb/d and 1.8 Mb/d respectively (in our assessment), the associated price risk has shifted from bearish, when output was ramping up, to bullish, with uplift worth $0-5.00, depending on the lost volumes and crude demand seasonality; − finally, in a low-probability but high-impact scenario, the US could unilaterally re-impose banking and financial sanctions on Iran; this could quickly remove a large volume of crude (of the order of 1 Mb/d or more) from the mar-

Oil supply, demand, and price forecast tables SG short-term oil supply, demand, and price forecasts Mb/d

2016

1Q17

2Q17

3Q17f

4Q17f

2017f

1Q18f

2Q18f

3Q18f

4Q18f

2018f

OECD demand

46.9

46.6

47.6

47.8

47.2

46.7

47.8

48.1

47.5

Non-OECD demand

49.3

49.6

50.9

50.4

51.0

50.5

51.0

52.2

51.8

52.4

51.8

World demand

96.1

96.5

97.4

98.0

98.8

97.7

98.2

99.0

99.6

100.5

99.3

*Non-OPEC supply

57.4

57.8

58.5

59.1

58.3

59.3

59.4

60.0

60.4

59.8

6.8

6.9

7.0

6.9

7.0

7.1

7.0

*OPEC NGLs *OPEC crude

32.8

32.1

32.3

32.8

32.5

32.8

World supply

97.0

96.7

97.0

98.2

98.8

97.7

99.1

99.3

99.9

100.2

99.6

0.9

0.2

-0.4

0.2

0.0

0.8

0.3

0.2

-0.3

0.3

NYMEX WTI ($/bbl)

Stock change

43.32

51.91

48.28

47.41

47.50

48.78

49.00

46.00

49.00

46.00

47.50

ICE Brent ($/bbl)

45.04

54.68

50.92

50.67

50.00

51.57

51.50

48.50

51.50

48.50

50.00

Source: Historical data – IEA, forecasts – SG Cross Asset Research Commodities. Note: IEA historical data from 11 August 2017 monthly Oil Market Report (OMR). *Non-OPEC supply includes processing gains and biofuels

SG long-term oil price forecasts 2015

2016

2017f

2018f

2019f

2020f

2021f

2022f

WTI NYMEX ($/bbl)

48.80

43.32

48.78

47.50

52.00

57.00

62.00

Brent ICE ($/bbl)

53.64

45.04

51.57

50.00

55.00

60.00

65.00

Source: Bloomberg, SG Cross Asset Research/Commodities

40 | MED OIL & GAS | November 2017

kets and provide $5 of upside for crude prices; however, the upside would be limited by high commercial crude stocks and also by quick increases in replacement sour crude from Saudi Arabia, Russia and other countries. •

OPEC “doubles down” on supply management. As discussed in the supply section, OPEC and Russia could implement a large new cut of 1 Mb/d to accelerate market rebalancing and push up prices (30% probability). This would provide $10 worth of price uplift.

Downside risks • Weaker economic and oil demand growth than expected. Any of the bearish risk factors in the SG macroeconomics “swan chart” could prompt slower oil demand growth. This could be worth $5 of downside for crude prices. • Weather-related disruptions. On the subject of hurricane-caused disruptions, we note the opposite situation to the one described above. In this scenario, which is similar to the one recently caused by Hurricane Harvey, refinery crude demand and product output losses are significantly larger than any related crude output losses. This scenario is bearish for crude and bullish for products, and can cause crude prices to drop by $5. • Geopolitical risks. Downside geopolitical risks are related to risk aversion and the possibility of a negative impact on economic growth. In the current global landscape, the top of our list would be an escalation of the ongoing crisis with North Korea. This could be worth $5 of downside for crude prices. • OPEC “throws in the towel” and abandons supply management. As discussed in the supply section, OPEC and Russia could return to the 2014 market share strategy and increase production (10% probability). This would cause crude prices to drop by $10.

Summary Our fundamental outlook through 2018 has become weaker. We expect global oil demand growth to remain healthy at 1.6

Mb/d, driven by emerging Asia and the US; however, global supply remains ample. We project non-OPEC output plus OPEC NGLs to grow by 1.6 Mb/d, led by 1.15 Mb/d from the US. This is enough to meet global demand growth. We assume, though, that OPEC maintains current production targets through 2018, with crude output flat at recent levels of 32.8 Mb/d. This results in an annual OPEC production increase of 0.3 Mb/d next year, which means that global stocks build by the same 0.3 Mb/d. As a result of the moderate oversupply, our crude price outlook has been revised down. Our forecast is broadly range-bound, and bearish with respect to current front-month prices and forward curves. We forecast front-month ICE Brent prices at $50.00 in 4Q17, $51.50 in 1Q18, $48.50 in 2Q18, and $51.50 in 3Q18. Based on normal $10-wide trading ranges, we expect Brent to trade in a $43.50-$56.50 range over the next 12 months. On an annual basis, we forecast Brent at $51.55 for 2017 and $50.00 for 2018. For front-month NYMEX WTI prices, our forecasts are $47.50 in 4Q17, $49.00 in 1Q18, $46.00 in 2Q18, and $49.00 in 3Q18. Based on normal $10-wide trading ranges, we expect WTI to trade in a $41$54 range over the next 12 months. On an annual basis, our forecasts for WTI are $48.80 for 2017 and $47.50 for 2018. In our base case, longer-dated crude prices should remain anchored around $50, the marginal cost of US shale production. At the same time, the continued oversupply indicated by our inventory forecast should broadly weigh on the front of the crude forward curves, generally keeping markets in contango (front-month vs 1-year forward). OPEC poses the biggest upside and downside risks to our outlook. OPEC could “double down” on cuts (30% probability), which would be very bullish (+$10 to $60 Brent). It could also “throw in the towel” and return to a market-share strategy (10% probability), which would be very bearish (-$10 to $40 Brent).

Mike Wittner Managing Director Mike Wittner is the Global Head of Oil Research for Societe Generale Corporate & Investment Banking. Mike is directly responsible for short-term and long-term global oil market analysis and forecasting. He has been ranked in the top 4 for oil market research in 2009-2017, according to Risk and Energy Risk magazines, including five consecutive years at #1 in 2013-2017. Since 2011, Mike has also been consistently in the top 5 for crude oil price forecast accuracy in Bloomberg’s quarterly ranking of the “best forecasters of energy prices”. With more than 20 years of experience in oil market analysis and, before that, 8 years of experience in the geosciences, Mike has extensive knowledge of the global and regional crude oil and refined product markets, geopolitics, and non-fundamental oil market drivers. He joined Société Générale Corporate & Investment Banking in 2007 from Credit Agricole, where he held a similar position. Prior to that, he held senior analytical positions at Koch Supply & Trading, the International Energy Agency, and PIRA Energy Group. Before getting his MBA, he worked as a geologist and project manager for an engineering firm and as an analyst at the Central Intelligence Agency. Mike holds a BS in Geology from Cornell University and a MBA in International Business from George Washington University. Mike is a regular speaker at industry conferences and seminars. His commentaries on oil market developments are frequently quoted in the international media and he appears regularly on television news programs. Media interviews have included CNBC, Bloomberg TV, CNN, the BBC, the CBC, the Wall Street Journal, the Financial Times, the New York Times, the Economist, Business Week, the wire services, and the energy trade press.

Disclaimer ANALYST CERTIFICATION Each author of this research report listed on the cover hereby certifies that the views expressed in the research report accurately reflect his or her personal views, including views about subject securities or issuers mentioned in the report, if any. No part of his or her compensation was, is or will be related, directly or indirectly to the specific recommendations or views expressed in this report. The analyst(s) who author research are employed by SG and its affiliates in locations, including but not limited to, Paris, London, New York, Hong Kong, Tokyo, Bangalore, Frankfurt, Madrid, Milan, Seoul and Warsaw. CONFLICTS OF INTEREST This research contains the views, opinions and recommendations of Societe Generale (SG) credit research analysts and/or strategists. To the extent that this research contains trade ideas based on macro views of economic market conditions or relative value, it may differ from the fundamental credit opinions and recommendations contained in credit sector or company research reports and from the views and opinions of other departments of SG and its affiliates. Credit research analysts and/or strategists routinely consult with SG sales and trading desk personnel regarding market information including, but not limited to, pricing, spread levels and trading activity of a specific fixed income security or financial instrument, sector or other asset class. Trading desks may trade, or have traded, as principal on the basis of the research analyst(s) views and reports. As a general matter, SG and/or its affiliates normally make a market and trade as principal in fixed income securities discussed in research reports. SG has mandatory research policies and procedures that are reasonably designed to (i) ensure that purported facts in research reports are based on reliable information and (ii) to prevent improper selective or tiered dissemination of research reports. In addition, research analysts receive compensation based, in part, on the quality and accuracy of their analysis, client feedback, competitive factors and SG’s total revenues including revenues from sales and trading and investment banking. IMPORTANT DISCLAIMER: The information herein is not intended to be an offer to buy or sell, or a solicitation of an offer to buy or sell, any securities and has been obtained from, or is based upon, sources believed to be reliable but is not guaranteed as to accuracy or completeness. Material contained in this report satisfies the regulatory provisions concerning independent investment research as defined in MiFID. Information concerning conflicts of interest and SG’s management of such conflicts is contained in the SG’s Policies for Managing Conflicts of Interests in Connection with Investment Research which is available at https://www.sgmarkets. com/#/compliance/equity or https://www.sgmarkets. com/#credit/compliance SG does, from time to time, deal, trade in, profit from, hold, act as market-makers or advisers, brokers or bankers in relation to the securities, or derivatives thereof, of persons, firms or entities mentioned in this document and may be represented on the board of such persons, firms or entities. SG does, from time to time, act as a principal trader in equities or debt securities that may be referred to in this report and may hold equity or debt securities positions or related derivatives. Employees of SG, or individuals connected to them, may from time to time have a position in or hold any of the investments or related investments mentioned in this document. SG is under no obligation to disclose or take account of this document when advising or dealing with or on behalf of customers. The views of SG reflected in this document may change without notice. In addition, SG may issue other reports that are inconsistent with, and reach different conclusions from, the information presented in this report and is under no obligation to ensure that such other reports are brought to the attention of any recipient of this report. To the maximum extent possible at law, SG does not accept any liability whatsoever arising from the use of the material or information contained herein. This research document is not intended for use by or targeted to retail customers. Should a retail customer obtain a copy of this report he/ she should not base his/her investment decisions solely

42 | MED OIL & GAS | November 2017

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Multi-phase Thermal History and its Impact on Hydrocarbon Development (Reggane Basin, Algeria) Introduction A comprehensive study on basin development and hydrocarbon potential was performed in the Palaeozoic of the Reggane Basin (central Algeria), with special focus on the Devonian and Carboniferous. The studied wells represent a 150 km transect from the eastern margin of the Reggane basin towards the basin, corresponding to a composite seismic transect. Beside seismic interpretation and basin modeling, sedimentological analysis and palynostratigraphic correlations, also the thermal history of this part of the basin was studied, which is presented here. Palynostratigraphic analysis enabled detailed correlations along the margin - basin transect in the eastern Reggane Basin. It shows an almost continuous deposition from the Silurian to the Lower Carboniferous with some differences between proximal and distal wells. Minor stratigraphical gaps are observed in the Middle Devonian and partially at the Devonian-Carboniferous boundary. The uppermost Lower Carboniferous is missing in all studied wells, related to a first phase of basin uplift. In distal wells it is followed by Namurian strata, whereas in proximal wells it is overlain by ?Westphalian strata. This indicates a complex basin development in the Upper Carboniferous, limited by the Hercynian Unconformity at the top and overlain by Mesozoic to Cenozoic strata. All wells are penetrated by magmatic intrusions related to the Latest Triassic CAMP volcanism, but the number, frequency and stratigraphical position of the dykes differs between the wells. Therefore, different lith-

ological units are affected by the magmatic intrusions, different effects on the development of hydrocarbon systems. Palynofacies analysis shows an overall dominance of terrestrial derived organic material, particularly plant debris. Spores are the most common palynomorphs in most samples and therefore also used for palynomorph colour analysis. Preservation of terrestrial spores is partially poor, particularly in the lower part of the wells and in intervals of organic rich shales, which has to be taken into account for maturation analysis based on Spore Colour Index (SCI). Palynofacies shows two major depositional settings for the Palaeozoic basin fill in the study area: a proximal shelf system in the Lower Carboniferous and Lower to Middle Devonian, and a distal shelf to basin system in the Upper Devonian and most of the Silurian. Optical kerogen analysis shows a high gas generating potential from the Silurian to the Upper Carboniferous due to the continuous dominance of terrestrial derived organic matter, mainly plant debris. The shale units of the transgressive marine intervals in the Silurian and Upper Devonian show also some potential for generating oil. Previous studies have proposed, that hydrocarbon generation was mainly linked to the phase of reburial during the Mesozoic, Pre-Hercynian hydrocarbon generation can be neglected (Purdy & MacGregor 2003). But thermochronological data indicate different phases of maturation. Burial con-

trolled primary maturation is developed before the peak of the Hercynian orogeny (pre-Early Carboniferous). It is followed by secondary heating in the latest Triassic, leading to maturation of middle to upper gas window, which is still observed today (Logan & Duddy 1998). The late Triassic secondary heating is related to the doleritic dykes in the Reggane Basin, which are part of the development of the Central Atlantic Magmatic Province (CAMP). The goal of the present study is to decipher the thermal history, identifying the different thermal events and their impact on hydrocarbon generation in the area. It is based on integrated organic maturation analysis, using high-resolution analysis of palynomorph colors combined with vitrinite reflectance analysis.

Methods In this study thermal history was analysed by integrated organic maturation analysis, based on the combination of a high-resolution study of palynomorph colours combined with vitrinite reflectance analysis in less resolution. Palynomorph colours were analysed in transmitted light, using the Spore Colour Index (SCI), because in all samples spores were present. Spores were carefully checked to separate in-situ from reworked specimens and also regarding the preservation of spores. For maturation analysis only well preserved specimen from the in-situ spore assemblage was chosen. The maturation analysis of the chosen specimens was based on the SCI reference standard slide set. 45

Vitrinite reflectance (VR) was measured in selected samples of all four wells, leading to the direct calculation of maximum palaeo-temperatures to cross-check and calibrate the SCI data sets. VR analysis was performed on polished blocks of concentrated kerogen isolated from the rocks by maceration. VR analysis was done by digital image based analysis of vitrinite particles. Classical photometer-based VR analysis of small vitrinite grains, typical in dispersed kerogen of sedimentary rocks, causes severe problems. Reflectance is measured from all components within the measuring field of the photometer, not only from the vitrinite particles, leading to mixed reflectance values of vitrinite and the surrounding material. Therefore, VR analysis in this study was done, using digital image analysis of high-resolution digital black I white images of vitrinite, taken at a reflected-light microscope. Grey levels of digital images represent the grade of reflectance and are re-calculated to real

VR values by image analysis software. This enables high-resolution reflectance analysis of single vitrinite grains down to pixel-size (<IO µm) without any negative side effects, providing highly accurate and reliable VR data without any correction factor. It also supports the identification of in situ vs. reworked and well-preserved vs. degraded vitrinite in mixed vitrinite assemblages and also the separation of real vitrinite from vitrinite-like particles. For VR analysis 100 particles of well preserved, clearly identified vitrinite grains were measured (if available). VR analysis provides maximum paleotemperatures of the studied rocks. Long term thermal events related to burial history show a similar level in VR basin wide. Short term and local heating events like magmatic intrusions are recognized by only locally divergent levels of VR.

Organic maturation in the eastern Reggane Basin Organic maturation was studied in four wells along the transect from the eastern basin margin into the basin. Well 1 and 2 are lo-

cated closely at the basin margin while well 3 and 4 are located further into the basin. In all wells palynomorph colours were continuously studied in high-resolution using the spore colour index (SCI). Additional vitrinite reflectance (VR) was analysed in less resolution for cross-check and calibration of organic maturation in the wells. Resolution of VR differs between the different wells and is limited to the Devonian-Carboniferous only. Both data sets fit very well to each other. Generally, in all wells a continuous increase of maturity is observed (Fig. 1, yellow line) from the Top Lower Carboniferous to the Silurian. This widespread maturation pattern is a result of burial heating and gives evidence for ongoing basin subsidence from the Silurian to the Top Lower Carboniferous. At the basin margin (well 1 and 2) maturation ranges from the top oil window (Rm 1,3-1,45%) in the Lower Carboniferous to the middle gas window (Rm 1,8-2,0%) in the basal Devonian to Silurian. Towards the basin (well 3 and 4) maturation generally increases. In well 3 it ranges from mixed zone maturation (Rm 1,6-1,8%) in the Lower Carboniferous

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Fig 1 Figure 1 Organic maturation in twr> wells from the eastern Reggane basin and the effect of secondary heating by CAMP related magmatic dykes. Light blue lines present palynomorph colours (SCI) and purple dots vitrinite reflectance data. The yellow lines indicate the primary, burial controlled maturation gradient, which ispartially overprinted by the secondary heating of the magmatic dykes (dark red). The greyish intervals at the bottom of both wells represent productive gas generating source rock units activated by burial maturation. The light purple interval, only present in well 3, covers productive gas generating source rocks in the Upper Devonian, activated due to the secondary heating by magmatic dykes.

to the middle I upper gas window (Rm 2,22,3%) in the Silurian. Further into the basin, in well 4, maturation is even higher, ranging from the early-middle gas window (Rm 1,75-1,9%) in the Lower Carboniferous to the upper gas window (Rm 2,7-2,8%) in the Silurian. The increase of primary maturation from the margin into the basin indicates increasing burial depth in this direction. This corresponds to the variation of the recent depth of the Lower Carboniferous in the studied wells, increasing from 1400-1350m (well 1 and 2) at the basin margin to 2350m in well 3 and 2700m in well 4 further out in the basin. It also corresponds to the increas-

ing thickness of the Upper Carboniferous recorded in the wells, increasing from about I OOm in well I to 1300-l 500m in well 3 and well 4. The upper part of the Lower Carboniferous (upper Visean) is missing in all wells. The overlying sections differ significantly between the wells. At the basin margin the Top Lower Carboniferous is followed by Mesozoic strata in well 2 and in well 1 by about 1OOm of Upper Carboniferous (?Westphalian) which is overlain by Mesozoic. Towards the basin 13001500m of Upper Carboniferous strata (Na-

murian â&#x20AC;&#x201C; ?Westphalian) follow above the Top Lower Carboniferous hiatus. This indicates a phase of severe uplift in the eastern Reggane Basin related to the Variscan Orogeny at the end of the Lower Carboniferous - basal Upper Carboniferous (early Namurian). In the basin the deposition and therefore subsidence starts again as early as the middle Namurian, according to palynostratigraphical data from well 3. Maturation shows a jump from late oil maturation in the basal Namurian samples up to the lower gas window in the uppermost Lower Carboniferous samples. A similar but even stronger jump in maturation is 47

observed in well I from the Top Lower Carboniferous to the overlying ?Westphalian. Maturation changes from the late oil window in the uppermost Lower Carboniferous to basal oil window in the ?Westphalian. According to this jump of maturation a significant amount of section was eroded even in the basinal wells during the uplift at the end of the Lower Carboniferous I basal Upper Carboniferous. The jump of maturation in well 1 gives clear evidence, that also the basin margin was significantly buried again during the Upper Carboniferous, although almost no deposits are preserved from this interval. It shows a complex basin development during the Upper Carboniferous with clear differences between basin and margin. Despite the complex finish of the Palaeozoic basin development, the organic rich Silurian shales have been heated up to the middle to upper gas window in all four wells in the eastern Reggane basin during the Palaeozoic basin subsidence (pre-Top Lower Carboniferous). Therefore, the activation of the Silurian – Middle/Lower Devonian hydrocarbon system including the generating of gas from this system has already happened in the Palaeozoic. Apart from this primary burial controlled maturation the thermal history of the eastern Reggane basin is significantly affected by secondary maturation due to the penetration of CAMP related doleritic dykes (Fig. 1). Both, the number and the stratigraphic distribution of the dykes are totally different in the studied wells. Most dykes penetrate the Devonian and Lower Carboniferous. In the Silurian and Ordovician dykes are rare to absent. Around the dykes maturation is extremely uplifted, due to the massive heating by the magmatic intrusions. But even the biggest intrusions (thickness of > l OOm) show a relatively limited interval of increased maturation. It is interesting to observe, that single massive intrusions have a much lower impact on increasing maturation than swarms of several thin intrusions. In opposite to the burial related primary maturation, which affects the entire Palaeozoic basin fill within the eastern Reggane basin, the dyke related secondary maturation only affects restricted intervals within the Palaeozoic basin fill. Also maturation is extremely increased in these intervals, up to overmature conditions (SCI 10, VR 3,5%), this secondary maturation has only a limited effect on basin maturation and therefore on hydrocarbon generation in the eastern Reggane Basin. Due to the different stratigraphical positions of the dykes differ48 | MED OIL & GAS | November 2017

ent lithologies got heated up. At the basin margin (well 1 and 2) dykes affect mostly sandstone and limestone rich intervals in the uppermost Devonian and Lower Carboniferous. Towards the basin (well 3 and 4) massive dykes and additionally swarms of several thin dykes penetrate the upper Devonian, which is dominated by organic rich, mainly gas-prone shales (Fig. 1). In this setting the massive, dyke related increase in maturation (upper gas window) of an interval of several l OOm of gas-prone source rocks led to significant gas generation due to the secondary thermal overprint. Well 3 was the first well in the area having two significant gas shows: one in the lower Devonian, which is common in the entire basin, but an additional gas show in the Lower Carboniferous. This study reveals the reason for this second gas show and puts up a target for future exploration focused on settings, where potential gas-prone source rocks (Upper Devonian) get massively affected by magmatic intrusions.

Conclusions Basin development and hydrocarbon potential of the Palaeozoic of the Reggane Basin was analysed along a transect from the eastern basin margin into the basin. Palynostratigraphic analysis enabled detailed correlations along the transect, showing continuous deposition from the Silurian to the Lower Carboniferous with some differences between proximal and distal wells. In the Upper Carboniferous a complex basin development is observed due to the Variscan orogeny. All wells are penetrated by magmatic intrusions related to the Latest Triassic CAMP volcanism, but the number, frequency and stratigraphical position of the dykes differs between the wells. According to previous thermochronological data burial controlled primary maturation (oil window) is developed before the peak of the Hercynian orogeny (pre-Lower Carboniferous), followed in the latest Triassic by secondary heating to middle-upper gas window due to CAMP related dykes, which is still observed today (Logan & Duddy 1998). In contrast to this, the new data show a two-phased thermal history, which leads to two phases of hydrocarbon generation. Continuous burial up to the Lower Carboniferous led to basin wide middle-upper gas window maturation of Silurian source rocks, activating the Silurian-Lower Devonian gas play of the eastern Reggane Basin already in the Paleozoic (Lower Carboniferous). Late Triassic CAMP related magmatic dykes led locally to massive secondary heating, leading only in

one well to increased maturation of Upper Devonian source rocks. This activated a second additional Upper Devonian-Lower Carboniferous gas play in this well, which is less common the eastern Reggane Basin, limited to settings where potential Upper Devonian gas prone source rocks get significantly affected by CAMP related dykes.

Acknowledgements We are grateful to DEA Deutsche Erdoel AG, Hamburg, for all support and the permission to publish the data of this study.

Authors Hartmut Jager, Thilo Bechstadt (GeoResources STC) and Markus Mohr (DEA Deutsche Erdoel AG)

References Logan, P. and I. Duddy, 1998, An investigation of the thermal history of the Ahnet and Reggane basins, central Algeria, and the consequences for hydrocarbon generation and accumulation: Geological Society Special Publications, v. 132, p. 131-155. Purdy, E.G. and D.S. MacGregor, 2003, Map compilations and synthesis of Africa’s petroleum basins and systems: Geological Society Special Publications, v. 207, p. 1-8.

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Marex Reflects on the Role of the IMO in the Offshore Industry The sinking of the RMS Titanic on the early morning of the 15th April 1912 lead to the death of over 1500 passengers and crew. At the time of her launch, ships her size were only required to carry enough lifesaving appliances for 990 people, and even though the Titanicâ&#x20AC;&#x2122;s life boat capacity was 1178. Tragically, however the passenger vessel had space on her davits for up to 64 lifeboats with a capacity of 4000 people. Both the British and American inquiries into the sinking recommended that ships should carry enough lifeboats for all onboard, the boats should be inspected and regular drills should be carried out. On the 23rd November 1913, the first International Conference for the Safety of Life at Sea was held in London with representatives from over 100 different nations. After seven weeks, the conference produced the first Safety of Life at Sea (SOLAS) convention which covered topics such as radiotelegraphy, lifesaving appliances and vessel construction. The convention was to come into force on July 1st, 1915, however the outbreak of World War I meant that it was never formally ratified. In 1948, the International Maritime Organisation (IMO) (known back then as the Inter-Governmental Maritime Consultative Organisation) was ratified as a specialized agency of the United Nations and came into force in 1958. The first meeting was the following year when their first task was to adopt a new version of the SOLAS Convention. This was finally adopted on the 17th

June 1960, and from there the IMO was able to turn to other marine matters. Whilst the IMO was being developed into a fully functional organization, offshore oil and gas exploration was starting to take off. Kerr-McGee Oil Industries drilled the first productive well that was beyond the sight of land at 10.5 miles off the Louisiana coast in 1947, using the platform Kermac No 16. This was a very basic platform which only supported the derrick, all other services had to be provided by tender vessels. At the time, there were no suitable vessels available so Kerr-McGee were forced to convert a war surplus barge and a landing ship to provide the services and materials need for the platform. As oil exploration developed and drilling and production increased, the need arose for a drilling unit which could be moved from place to place and unlike the Kermac No 16, would have all the drilling infrastructure onboard and therefore minimise the need for attendant vessels, and so the submersible rig was born. The first submersible rig was the Breton Rig 20, designed by John T Hayward, converted from an inland drilling barge, which had columns that supported the drilling platform. When the rig was on location, the barge was submerged, which left the platform high above the water. Submerging the barge damped the motion of the rig so work could continue in relatively high swell and poor weather. The Breton Rig 20 had one major design flaw, due to her unconventional construc-

tion, she was very unstable during the submersion procedure. The first purpose built submersible rig Mr Charlie, solved this problem by using a pontoon on each side of the barge to improve stability. Another type of mobile unit was being developed by the Magnolia Company at the same time. Instead of submerging the hull to provide stability in the seaway, these mobile units were based on the Delong dock, which were barges fitted on tubular legs which were towed into place and the legs extended until the barge was raised out of the water. These barges were successfully used to build temporary ports after the D-Day landings. The Magnolia Company bought one of these barges and converted it into a drilling unit. The first purpose built jack-up unit was Scorpion, built by LeTourneauâ&#x20AC;&#x2122;s Vicksburg plant on the Mississippi. She consisted of a platform, built onto three independently operated lattice type legs which used a rackand-pinon system to jack up and down. Both, submersible, semi-submersible and jack-up rigs are generally recognised as ships and they often transit international waters, therefore they are bound by the regulations developed by the International Maritime Organisation, including the SOLAS Convention. There is scope in the SOLAS Convention to grant exemptions to vessels which have novel design features, but it would be unfeasible to exempt all mobile offshore drilling units (MODU) hence an alternative solution was required. 51

MODU’s have special construction requirements due to the nature of their work and the almost constant presence of explosive products and dangerous goods. Technology in the offshore industry is complex and can rapidly evolve so regulations have to be able to evolve as required. The IMO recognised that applying the SOLAS Convention to MODU’s was inappropriate so on the 15th November 1979, the Code for the Construction and Equipment of Mobile Offshore Drilling Units, aka the MODU Code, was adopted by the Assembly. The MODU Code provided for the different levels and standards of construction that would be applicable to the special nature of the offshore drilling units and to ensure the units provided a level of safety that was at least equivalent to the requirements of the SOLAS Convention 1974 and the International Convention on Load Lines 1966. The IMO recognised that the nature of offshore oil and gas exploration would be forever evolving and allowed for that in the preamble to the code, by stating that the Code should not remain static but be re-evaluated and revised as necessary and the Code should be reviewed periodically, taking into account experience and future development. In addition to the MODU Code, the IMO have developed a number of non-mandatory codes that specifically apply to the offshore industry due to the highly specialised nature of the work that they carry out. The Code of Safe Practice for the Carriage of Cargoes and Persons by Offshore Supply Vessels (OSV Code) was developed in

response to a number of incidents that occurred on supply vessels during cargo operations and personnel transfers. The Code was adopted on the 27th November 1997 and sets out requirements relating to the suitable pre-planning, stowage and securing of cargo, as well as port and offshore operations. Another non-mandatory code that relates to the offshore industry is Code of Safety for Special Purpose Ships (SPS Code) which was adopted on the 17th November 1983. In the SOLAS Convention, a passenger is defined as:

“Every person other than: (i) The master and the members of the crew or other persons employed or engaged in any capacity on board a ship on the business of that ship; and (ii) A child under one year of age.” If a vessel is required to carry more than 12 passengers, then the regulations for a passenger vessel must be applied. These regulations are significantly more stringent than would apply to a normal cargo vessel and include a requirement to have personnel with specific qualifications.

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broadly applies to all vessels, including offshore support vessels and MODU’s however, the day to day operation of these vessels differ greatly to the deep-sea trading vessels which will make up the bulk of compliant vessels, therefore the IMO have produced circulars which describe alternative options for MODUs and offshore vessels to meet the functional goals of the Ballast Water Management Convention. In my role as a Senior Marine Consultant with Marex Marine and Risk Consultancy, I work on a daily basis with many of these vessels referred to in this article and as such see first-hand the implications and value of the way the regulations are developed to adapt to the ever changing needs of the offshore Oil and Gas industry and the greater shipping industry.

As the offshore industry developed and vessels were required to carry out more specialised tasks such as dive support or survey work, a lot of the vessels found themselves having to comply with the passenger regulations due to the fact that they could potentially have more than 12 personnel who were not members of the vessels crew. These special personnel could be surveyors, client representatives, divers and technicians, and because of their background, they will be expected to be able bodied, have a fair knowledge of the vessel and be trained in the use of its safety features, therefore they do not need to be classed as passengers so the vessels do not have to comply with the SOLAS Convention passenger ship requirements if they comply to the SPS Code. The most recent development currently working its way through the IMO with regards to the offshore industry is the Code for the Safe Carriage of More than 12 Industrial Personnel On Board Vessels Engaged on International Voyages. It has been recognised that there is a growing requirement for carriage of industrial personnel in large numbers to offshore facilities such as windfarms. The recent helicopter incidents, and the Icelandic ash cloud in 2010 has meant that there have been periods when workers were transferred to and

from rigs by supply boat or walk to work vessels. Many of these vessels are classified as Special Purpose Vessels under the SPS Code, however the industrial personnel are not there to work on the vessel, they are simply being transported to and from their place of work so the SPS Code may not be an appropriate mechanism to Class new vessels which are specifically designed for the purpose of transporting industrial personnel. The IMO has recognised that these industrial personnel have received offshore training in the form of Global Wind Organisation or Offshore Petroleum Industry Training Organisation (OPITO) courses and are familiar with the use of safety equipment onboard vessels, therefore they shouldn’t be treated as passengers, so any vessels carrying industrial personnel may be exempt from complying with passenger vessel requirements. In order to facilitate this, the IMO are developing the SOLAS Convention to include a new chapter, 15, and associated Code which is expected to enter into force in 2024. In addition to developing specific regulations for the offshore industry, the IMO has recognised that it may be more efficient to allow alternative compliance methods. The Ballast Water Management convention

Author Captain Eilidh Smith BSc MNI, Captain Eilidh Smith, is a Senior Marine Consultant at Marex Marine and Risk Consultancy. She has over fifteen years’ experience sailing both worldwide on a variety of cargo vessels, and in the North Sea sector of the offshore oil and gas industry. As a marine consultant she conducts industry standard marine assurance and warranty inspections for a number of oil majors. Eilidh has recently been appointed to the Nautical Institute’s International Maritime Organisation committee, through which she attends the Marine Safety Committee meetings at the IMO on behalf of the Nautical Institute. For more information please see www. mmass.co.uk

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Practical Application of Energy Storage in Hybrid Commercial Vessels Grant Brown, Vice President Marketing, Plan B Energy Storage The new class of hybrid and full electric work vessel allows instant full power in milliseconds, avoiding the need to ramp up a generator to high power output. Plan B Energy Storage (PBES) is a leader in providing lithium batteries designed for use in marine applications. Commercial vessels gain tangible financial benefit from the addition of energy storage: the battery allows the vessel to operate on smaller, more efficient engines while maintaining their high performance required - with no compromise in safety. Introduction When you speak the word â&#x20AC;&#x153;hybridâ&#x20AC;?, people immediately think of a Toyota Prius; the economy car preferred by eco-enthusiasts around the world. Most people do not think of offshore supply vessels in winter storms in the North Sea, tugboats safely escorting chemical tankers through busy ports, or 500-foot passenger ferries running on a 24hour schedule, day in and day out. Marine engineers have long been aware of the potential efficiency increases from hybridizing their onboard energy systems, however, only recently has the battery technology been improved to the point of allowing large-scale systems to survive in a commercial marine environment. Not only do these new energy storage systems survive, they are designed for and excel in commercial marine environments. Hybrid tugboats, offshore supply vessels (OSV), ferries and a variety of other purpose built vessels all derive huge efficiencies from the use of onboard energy storage. These hybrids range from new builds to retrofits of existing vessels. Payback on investment is a critical component in the

decision to convert or build a hybrid workboat. However, an often-overlooked benefit is the redundancy and increased safety offered to the operator of a hybrid vessel. A vessel employing a large battery or Energy Storage System (ESS) not only operates more efficiently, it also has an ability to draw upon a reserve of energy instantly. This pool of energy may be used as spinning reserve to keep the vessel from harms way in the event of power loss, provide emergency navigation and hotel loads, auxiliary propulsion power and even extra bollard pull to the main drives in the event of an emergency situation while towing. While these and other advantages, such as the environmental and cost savings benefits, are well-documented, real world lessons learned by an experienced integration and engineering team are exceptionally valuable. This experience helps vessel owners, operators and designers understand how to design and integrate a lithium energy storage system for safe, reliable use, now and for years to come. Simply put, batteries will reduce a vessels exposure to risk and make it fundamentally safer to operate, while providing economic gain for vessel owners.

Tugboat Harbour tugs have a unique operational profile, they require huge amounts of thrust to provide the force required to tow ships many times their size, but spend very little total time at the upper range of that power output ability. Instead, the vessel spends much of its day transiting to and from jobs, holding position, or tied up at a dock. Using a five thousand horsepower engine to maintain position in a light tidal current is an extremely inefficient use of such a large engine. Not only does the engine burn as much or more fuel at idle than it does at optimum RPM, the poor combustion from low speed operation results in unburned fuel, wet stacking and results in increased maintenance and emissions. The hybrid tugboat increases efficiency in all these areas. The vessel still uses its large diesel engines for the heavy bollard pulls, but it also gains the ability of running on a secondary system â&#x20AC;&#x201C; the Energy Storage System. This means the vessel now has the ability to run most (if not all) low speed, low power operation on the batteries alone. The energy storage system eliminates low speed operation of the diesels, allowing them to be 55

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shut off until they are required for bollard pull duties. The resulting reductions in typical fuel consumption of 25%, maintenance of 25% and emissions by up to 75%, allows rapid payback of the system cost, often in a few short years, and a greatly reduced negative impact on air quality in and around the port. The American Bureau of Shipping now recognizes the safety of energy storage systems in hybrid tugboats, and some systems are now class type approved.

Offshore Support Vessels Considered some of the most brutal environmental conditions on the planet, offshore oil and gas production support vessels must maintain their intense operational duties regardless of the weather. A support vessel uses a dynamic positioning system to hold position relative to the rig despite wind, waves and currents. The vessel will typically ramp up onboard generators to provide the instant power that is needed to offset these forces, using it as needed and dumping the excess energy. This results in huge waste of the energy produced, wasted fuel and ultimately excess maintenance. An OSV using dynamic positioning with integrated energy storage gains significant efficiency over traditional propulsion systems. Rather than constantly run the generators to service the maximum power output requirement, the generators provide the mean amount of power. Spikes in load are serviced instantly with the high power output from lithium batteries – faster than could be achieved by ramping up a generator. Thus, the vessel is able to respond to variations in load (wind and waves) as they happen, on battery power alone. As the dynamic positioning loads are varied, the onboard generators replace the energy in the batteries during times of low loads. Often this results in a rapid charge/discharge cycle scenario and requires energy storage systems built to very strict performance parameters. This peak shaving allows smaller generators to be run at far more efficient loading, as they are essentially become battery chargers, resulting in dramatically reduced fuel consumption and maintenance requirements.

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Ferries generally run very predictable routes with predictable loads. Well-established patterns and data (weather, tidal and current information) from years if not decades of operation, and lengthy vessel life spans are typical. In many cases, ferries have been optimized over decades of operation and scheduled maintenance intervals. As a result, additional gains in efficiency come at significant cost and are often incremental. Without commissioning a completely new vessel, a ferry operator may now refit to hybrid propulsion during a scheduled maintenance break and complete the conversion in a matter of weeks, losing no operational time. In large ferries, the energy storage system for the ship is set primarily for low speed operations, station-keeping positions and house power; avoiding diesel engines running at non-optimal load. This enables battery-only operation for loading and unloading, and entry and exit within the harbour and the vessel is now able to meet increasingly strict harbour emission requirements. Class societies recognize the robustness of the new energy storage systems and now approve their use as stand alone spinning reserve, eliminating the need for a redundant generator. The op-

portunity for load leveling provides a high level of fuel efficiency and reduces the number of generating sets, enabling the ferry to optimize its fuel consumption by adjusting its engine output. Thus, a typical large (1000 passenger) ferry is expected to reduce carbon dioxide emissions by up to 15%, fuel consumption by 25% and maintenance by 30%. In ferries with shorter routes, the vessel may be hybridized to run on electricity while under way and while idling at the dock. In this case, the vessel uses the diesel engines to provide initial propulsion while leaving the dock and then reverts to electric only operation. Increasingly, the vessels are being refit to full electric propulsion using batteries only. This signals significant trust in the reliability and longevity of todayâ&#x20AC;&#x2122;s battery technology and allows the operator to move from fuel, emissions and maintenance reductions to fuel and emissions elimination. PBES batteries are found in the worldâ&#x20AC;&#x2122;s largest fully electric ferry, 2500 ton Tycho Brahe in Denmark.

Spinning Reserve and Emergency Power In previous years, the hybridization of commercial vessels was viewed as a novelty, one whose time has not yet come. Today, the reality is far different. The new hybrid and full electric vessels have earned their place at the table and provide tangible economic and environmental benefits. These benefits are in and of themselves enough to persuade owners and operators to go hybrid, but it gets better. The hybrid vessels all come with a huge source of emergency power that responds in milliseconds. The 2490 ton hybrid ferry Princess Benedikte has a 2.7MWh battery that is capable of providing 30 minutes of full speed propulsion and up to 2 hours of manoeuvring at low speeds. This is longer than the total time to cross the full Denmark to Germany route it services. In the event of an emergency situation, it provides ample time for other vessels to deliver assistance and enough power to make headway to land (albeit at lower speeds), should the vessel have lost diesel prime mover capabilities. In a hybrid OSV or tugboat, the vessel has similar added capabilities. Depending on the size of the installed energy storage system, the vessel may be able to provide an additional amount of thrust or increased bollard pull to prevent an emergency situation from escalating, additional speed to provide res-

cue or assistance, or full electric, spark-free operation away from an explosion risk. DNV-GL now recognizes the safety and reliability of PBES energy storage systems in hybrid offshore supply vessels and recently Type Approved the PBES system.

Advances in Technology Battery technology that has been designed for marine use is now commonly used in Europe and is considered reliable and robust. That said, several design considerations must be implemented to ensure a safe, reliable and long-lasting hybrid vessel. For the limited scope of this article, this technology section will examine the latest in technology for lithium ion battery systems, specifically lithium polymer batteries using a Nickel Manganese Cobalt cathode material (NMC). NMC is the industry standard in heavy industrial energy storage. It contains greater energy density than other types of lithium ion batteries and is able to provide high current power to enable heavy machine starts, such as those of thrusters and main propulsion. In fact, modern energy storage systems are capable of providing multiple times their rated capacity in use, further increasing their usable power. The latest PBES technology offered to the marine industry is capable of providing a 3 times capacity, 24hour average continuous discharge current. For example, a 10 Megawatt hour battery is capable of providing an average of 30 Megawatts of power continuously being charged and discharged until all the energy is depleted, with no increase in temperature, degradation in performance or negative effect on lifespan. Modern advances in ESS technology have moved away from the use of high voltage, high amperage single breakers on

the DC bus, to modular systems, each with its own internal contactor creating a lower voltage, safer and less costly system overall. The lower voltage system reduces the safety risks associated with a single high voltage breaker. When the system is deactivated, it is essentially inert with each sealed module capable of putting out only 100V. With modern ESS achieving up to 1500V on the DC bus, and currents of up to 450 amperes, the inherent risks to personnel are greatly reduced with the lower voltage system.

Energy vs Power Cell Differences In some cases the vessel will never require the extremely high currents and discharge rates required by a high power application like and OSV. In this case, the PBES system will be designed with a low power cell. Outwardly the system looks identical and is the same in all ways except one: the cells have greater energy density (resulting in a 10kWh module as opposed to the 6.5kWh module in a high power system). Because the energy density is increased, the battery will have a smaller size, weight, price and installation/integration cost. The form factor in the energy system is identical; therefore a cost savings is achieved in manufacturing that is passed on to the customer. If a vessel ever changes duty the battery can be changed to a higher or lower energy density without changing the racks, cooling system or cabling increasing flexibility over the life of the vessel.

Installation Each installation (vessel type and size) presents a unique safety and performance challenge, however, most modern hybrid vessels rely on a common format - diesel electric generators - powering electric drives, aug57

mented by high power lithium batteries. Installation is very straightforward and may be completed by any competent shipyard. Typically, the battery is assembled in a modular form factor of 10kWh or less per module and configured in a series string to meet needed bus voltage. Parallel strings are added to make up the desired system capacity. The modules are loaded into an integral and engineered racking system affixed to the structure of the vessel. Retrofit hybrids using modern energy storage systems are tuned to communicate with existing onboard power electronics. Software may be written to bridge any gaps that older onboard systems may present. New build hybrids have the advantage of implementing control equipment, generators and inverters, from major OEM manufacturers. These major OEM companies work closely with reputable energy storage companies to develop complete systems that communicate freely and allow seamless and quick deployment, usually in line with traditional timeframes for typical haul-out maintenance.

Energy Storage System Location Due to the limits of typical vessels, space is at a premium, center of gravity and the displacement of the vessel directly affects the performance during work duties and while transiting. When a potential operator or owner considers the move to a hybrid propulsion system, they are often very concerned about additional weight and size of the energy storage system. Due to the high energy density and discharge abilities of the new generation of batteries, the systems required to meet typical missions are smaller than ever and are not generally considered to affect the balance or handling of the vessel. Often a net savings is achieved by removing generators that are now redundant. The fact that the systems are connected to the DC bus means that the system is light and small enough to be located in any location on the vessel, however a location near to the engine room is preferred. Generally a completely separate battery room is created with a separate bulkhead and door, however PBES systems are fully self-contained and in effect create their own room. The PBES system has been tested to the highest

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standards for thermal runaway propagation and is the only system on the market that is actually proven to prevent thermal runaway in the first place.

Racking for Energy Storage System The advanced energy storage systems of PBES employ an integrated, highly engineered racking system. Strength and weight are very significant considerations and other components come into play as well. PBES uses integrated liquid cooling to achieve the lifespan, performance and extreme discharge rates demanded by workboat applications. The plumbing of the cooling system, such as pipes, connections and other components, are integrated into the rack design to avoid potential mechanical damage during installation or day to day operation. Plumbing considerations aside, the racking system must be strong, light weight and easily configurable to allow it to adapt to a large variety of vessel designs and configurations. In order to reduce the weight of an installed system, the racking should be integral to the finished system, allowing it to operate without compromise. PBES ener-

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gy storage systems also provide integrated module venting to prevent risk of explosion. In the unlikely event of a cooling system failure and over heating resulting in the modules entering thermal runaway, flammable gasses emitted from the consumed battery cell material will be automatically self-vented to the exterior of the vessel. This effectively eliminates all potential for explosion.

Fire Suppression Given the possible issues associated with fire and explosion, the class groups have spent a lot of time focusing on how to prevent and manage fires and thermal runaway. No matter the amount of care that the class rules can apply to prevention, it does not remove the battery manufacturers from the responsibility of incorporating sophisticated prevention systems into the design of the batteries. With lithium energy storage systems now regularly being discussed that exceed several MWh of capacity, the risk of thermal runaway or fire cannot be taken lightly. Todayâ&#x20AC;&#x2122;s hybrid designs must take this into account and do everything possible to ensure that a fire cannot start in the first place. This has created a shift in thinking that is driving designs to incorporate liquid cooling systems. These liquid cooling systems manage battery safety inside the core of the module through temperature control and management at the cell level. Fire suppression is critically important but must be viewed as a secondary system to manage

the issue in extreme circumstances, after all else fails. Fire suppression systems therefore are recommended to control external fires adjacent to the energy storage system to prevent them from causing a thermal event in the battery room. If desired, fire suppression in the battery room may also be employed to further give peace of mind as a backup system. Mist type fire suppression provides adequate cooling to suppress virtually any fire (outside of a major catastrophe involving the ship itself) that may pose a hazard to the energy storage system. In order to meet class standards, the energy storage system itself must be rated for IP67 water resistance and therefore able to safely withstand activation and use of mist type fire suppression.

Management Systems, Communications and Controls Modern battery systems provide an ability to not only integrate with existing systems

onboard the vessel, but also increase longevity of system life and enhanced safety of the system. These systems reside inside the battery modules and the system controller, which in turn communicates with the other vessel power electronics. The Battery Management System (BMS) is able to predict module lifespan using complex algorithms that incorporate historical data and projected future use. This allows the vessel owner to alter their use profile of the energy storage system to a) increase lifespan b) increase vessel fuel efficiency or c) a combination of both. The BMS is also an extremely important part of the safety system of the ESS. It constantly monitors the internal core temperature of the modules and if they are going out of spec (too hot or too cold), they will warn the vessel captain to limit use. The BMS is also able to actively monitor the state of health of the system within the temperature warnings, if a specific component in any one part of the entire system is out of spec, the system will warn the captain and the team who is monitoring it. The monitoring team will then proactively engage with the vessel and determine what, if any course of action need be taken. If the warnings continue without intervention from the team, or if the vessel crew ignores the warnings, the system will protect itself and the vessel by disengaging from the DC bus and isolating all the modules in the system via their internal contactors, effectively reducing system voltage from a maximum of 1000V to ~100V (the voltage of a single 59

module). As the controls are powered separately from the ESS, they are safer in that there is redundancy in the system. It will always have an external power source ensuring the cooling system is operating and the management system is communicating with the vessel and system administrator team at all times, regardless of the system status.

Charging Infrastructure The modern ESS requires the ability to communicate with and control the charging infrastructure of the batteries. All lithium batteries are very sensitive to voltage and current. Voltage must be kept at a constant setting specified by the manufacturer. The BMS must be able to direct and control the charging system to increase current at specific set points to increase charging rates, ultimately to decrease charge times and optimize usefulness of the system. Conversely, the BMS must also be able to reduce current at other times to increase longevity of the system and meet the vessel ownerâ&#x20AC;&#x2122;s objectives for lifespan of the system. The BMS will take all types of information from the modules and surrounding systems, such as temperature, state of charge and system age, to determine the best charging profile at any given time.

Cooling Systems While the industry standard for many years was passive cooling on all systems, it is increasingly apparent that the smaller systems demanded by industry are required to operate at, or beyond, the limits of passive cooling. Virtually all modern ESS employ some form of liquid cooling, either as an optional addition to the standard system or as an integral component. Advanced, state of the art ESS, use individual cell level cooling systems; the coolant circulates within the very core of the battery module at a low pressure enabling far greater charge and discharge currents, increased lifespans and reduced system sizes. In fact, the most modern of these systems has been validated to discharge approximately 16 times more power than the current industry standard product. Typically the ESS will connect to a standard chiller of specified size, using an inexpensive and small pump and be able to meet the very high demands with a far smaller system size and capacity with resulting cost savings benefits.

60 | MED OIL & GAS | November 2017

End of Life Disposal PBES takes the issue of electronic waste very seriously. In many jurisdictions where our batteries are sold there are serous requirements for sustainability plans. As a result, we developed CellSwap, a way of reducing the amount of waste put into the e-waste recycling stream and reducing costs for customers. Simply put, CellSwap is a way of rebuilding the battery at end of life, reusing all of the non-consumable parts and only replacing the cells. Similar to an engine block in a generator, it is often more economical to replace pistons, rings, and bearings rather than replacing the entire system. As a company founded and directed by a team with true marine heritage, this only makes sense to us. CellSwap customers only pay for the new cells and the manpower to replace them. All of this can be done on site while the vessel is undergoing routine maintenance and does not disrupt normal operation. Best of all, the amount of waste is reduced by more than 70% compared to replacing the entire system.

Conclusion The new breed of hybrid commercial vessel is now a proven workhorse capable of huge economic and environmental benefits in virtually every application it is deployed. The added risk mitigation and increased safety has tangible value that should not be dismissed. No longer is the reduced cost of ownership from the decreased fuel consumption and maintenance outweighed by concerns about safety and reliability. As with any updated technology, lithium energy storage is new and system design is currently being refined, as are class rules regarding the use of the technology. As a co-founder of one of the early companies developing energy storage for hybrid marine systems, I have observed the industry develop, grow and mature. It is my assertion that the technology is gaining momentum by leaps and bounds. As it continues to evolve so will advances in the design and safety of the systems. The industry is now producing safe, reliable systems that provide meaningful financial benefits for the owners, safe operation for the crew and ultimately, huge environmental benefits for the planet.

Author Grant Brown Vice President Marketing, PBES, As a founder of the first company building purpose engineered marine energy storage, Mr. Brown has helped define the industry since 2009. After nearly a decade working with the leaders in OEM commercial marine power systems, he has extensive knowledge of the business, drivers and the technology that is enabling the shift to green propulsion. A lifelong boater and outdoorsman, Grant is driven by a need to â&#x20AC;&#x153;leave it better than he found itâ&#x20AC;?. This drive combined with an innate ability to understand power solutions of all types, gives him the ability to explain the benefits energy storage to the world, and inspire others to become a part of the change.

Beyond MPD: Introducing Enhanced Primary Well Control (EPWC) Paul Sonnemann, SafeKick, Helio Santos, SafeKick, and David Gouldin, Seadrill Managed Pressure Drilling, or MPD, has become widely regarded as a significant benefit by operators and contractors worldwide. It remains apparent, however, that many in the industry have not yet recognized that the equipment and processes currently used successfully for MPD can provide benefits well beyond the ability to solve the drilling problems for which the MPD system and service was deployed. But before discussing how these benefits may take us “beyond MPD”, consider where the industry currently stands with respect to MPD. Many operators/contractors have seen major improvements in the ability of MPD systems to: • Improve ease of use (simplified HMIs) and performance of chokes used to maintain specific pressures either at surface or downhole while circulating at drilling rates • Greatly improve accuracy of measurements of both flow out and flow in while circulating (e.g. by use of Coriolis flow meters) • Greatly improve the real-time measurement of fluid densities entering and returning from the well (e.g. by use of Coriolis flow meters) • Improve awareness and use of real-time downhole pressure measurement (e.g. by use of PWD tools) • Improv display and control of returned fluid flow paths through complex manifold systems

• Improve real-time awareness of pressures along the entire wellbore, including assessment of conditions with a narrow drilling window (e.g. by use of real-time hydraulic models) • Mitigate hazards associated with unpredictable exposure to massive lost circulation One way to summarize the net benefits commonly provided by MPD is to recognize its impact on our ability to precisely manage downhole pressure relationships. In fact, one might characterize the success of MPD by its ability to broaden the scope of what has long been defined in the industry as “primary well control”, which traditionally refers to the practice of ensuring that hydrostatic pressure alone remains sufficient to balance or overbalance the pressure of any exposed permeable formation. Even when MPD practices are used to reduce pressure fluctuations at a key wellbore location, they must include the ability to continuously monitor and maintain pressure balance sufficient to prevent and or detect

continuous inflow of formation fluids, the major objective of primary well control. To accomplish this in practice, all operations currently defined as MPD must prevent replacement of measured, relatively uniform drilling fluids by produced fluids because: 1. Hydrostatic pressure of the drilling mud remains the major source of downhole pressure needed to balance formation pressures. Replacement of relatively heavier drilling fluids by lighter formation fluid inevitably reduces downhole hydrostatic pressure and must therefore be prevented or limited to avoid excess fluid contamination. 2. Excessive contamination of wellbore fluid column by produced formation fluids may hinder or render inaccurate the specific technique being used to model or monitor important downhole pressure relationships such as the relationship between wellbore and formation pressures along all open hole sections. While suitable models may exist, their use during real time events im63

pacted by imperfectly known fluid and pressure conditions downhole makes it hard to ensure reliable multiphase calculations. But as long as fluid and wellbore conditions remain sufficiently known and consistent, MPD systems can reliably achieve the goals of primary well control by reliably preventing undesirable influx.

When this goal is achieved, the additional equipment typically required for MPD services provides the opportunity to manipulate or “fine tune” downhole pressure relationships much more quickly, easily and precisely than is possible when using only fluid density for primary control. Since this equipment uses barrier elements independent from, but not in replacement of, secondary well control barrier elements (e.g., BOP,

choke/kill lines, rig chokes), such use of MPD equipment does not damage or alter the rig’s normal capacity to respond to situations in which the primary well control barrier has been lost. And not insignificantly, MPD equipment is designed for continuous use during drilling operations and, as such, generally permits use of much higher pump rates than is possible through the secondary BOP system, while also managing removal of cuttings, junk and some gas within the returning mud stream. In light of this, the MPD industry is currently moving toward redefining “primary well control” during MPD operations, recognizing that some level of fluid contamination in the annulus may make it difficult to truly ascertain and quantify the effectiveness of the combined effects of hydrostatic pressure, surface back pressure, and annular friction.

Next Generation MPD System: Available and already field proven › Field Proven in Alaska, US Shale Oil and deep water GOM, vertical and horizontal wells › A full range of MPD systems, from the simple APOD – Annular Pressure on Demand – to the complete Safe-MPD, to suit different types of wells › With the experience gained from developing one of the first MPD systems, more than 10 years ago, the SafeKick team implemented several new features – Firsts in the MPD industry: • Intelli-Choke® electrically-actuated chokes providing improved positioning and pressure control • Use of Intelligent Predictive Control (IPC) instead of the commonly used PID control • Big bore 6” choke to greatly reduce the friction loss generated by the MPD system • Integrated Valve Control System • Simple interface allowing the rig crew to directly operate the MPD system

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64 | MED OIL & GAS | November 2017

While there may be understandable reluctance within the broader drilling industry to redefine a term as important and common as the term “primary well control” (PWC), it is worth noting ways in which the current definition can lead to some field practices that blur the clear distinction between primary and secondary well control- thereby often compromising both safety and efficiency of conventional operations. Consider the following examples in which conventional primary well control (PWC), by definition, is maintained and confirmed (e.g. by a successful flow check during which the well is observed to remain static) but is less than certain or reliable: • Reliance on trip margin calculated to exist by use of estimated (not measured) pore pressure and without consideration of changes caused by cuttings removal makes avoidance of swabbed-in influxes a trial and error process. • Use of trip sheets to monitor pit levels to compensate for volumes change during tripping operations, when interpretation requires tolerance for effects of slugs and non-uniform pipe string geometry, leads to false kick indications during trips which both reduces efficiency and may mask and delay prompt response to real kick events. • The recommended practice of “tripping back to bottom”, rather than “stripping back to bottom” in response to noting a trip sheet discrepancy and completion

of a subsequent, successful flow check to confirm that the well remains static can cause sudden loss of PWC if the string enters and elongates a section of the well filled with low density produced fluids. • The practice, particularly during HPHT operations, to ensure that no more than 1 or 2 “connections” (i.e. areas of possibly influx-contaminated mud) remain within the annulus prior to making an additional connection.

For these reasons, MPD operations generally include preparation of some sort of guideline as to what combinations of formation fluid influx volume and magnitude of hydrostatic underbalance can be managed, individually or in combination, without loss of the ability to quantify and control downhole pressures within operational limits. This guideline may take the form of an operations matrix or an “influx management envelope” intended to clearly define what combinations of surface pressure and influx volume will not exceed the defined performance capacity of the sys-

tem (i.e. defined combinations of influx and required surface back pressure that will not cause loss of primary well control) and those that do exceed defined system limits (which clearly require application of secondary well control equipment – generally closure of the BOP). The figure below shows an example of such a matrix, with limits to the system’s primary well control functionality clearly indicated (All conditions shown in red are beyond the primary well control limits and require immediate action to close the BOP).

• Circulation needed to identify the possible influx of formation fluid in a high angle/horizontal well may lead to sudden loss of PWC if/when influx fluids enter relatively vertical portions of the well. Use of MPD equipment can easily be shown to improve the ability to maintain control during many common drilling events such as these, which involve uncertain PWC. If one additionally considers the challenge of maintaining and confirming PWC during cementing, workover, and completions operations, it is easy to propose ways in which MPD equipment could be used to augment and help confirm reliability of the primary barrier, though many people would probably not define such usage as within the usual scope of MPD applications. Given its benefits, it may indeed be tempting to extend use of MPD equipment to secondary well control practices. But it is important to remember that pressure limits of MPD equipment are generally far too low to permit use of the MPD system to balance formation pressure if a) too much hydrostatic pressure is lost due to excessive inflow or b) the well becomes exposed to formation pressure much higher than predicted. It should also be remembered that, unlike conventional BOP equipment, MPD equipment is generally not designed or included in training for management of conceivable “worst case” conditions and may in fact suffer performance degradation due to its routine use since the time of whatever testing may have previously been performed. Since protection from possible, albeit unlikely extreme potential conditions remains important, even during MPD operations, it is important to continue to maintain secondary well control barrier elements in a ready state, and plan for their emergency activation should the need arise.

Fig. 1 Example of MPD Operations Matrix providing well control details during drilling operation only

Fig. 2 Example Well Control Operations Matrix that illustrates broad, Enhanced Primary Well Control scope 65

So long as MPD operations remain within such pre-defined limits, the systems can enhance the ability to continue operations without need for reliance on secondary well control equipment even when conventionally defined primary well control is uncertain. One long-standing impediment to full appreciation of MPD benefits to deepwater, subsea stack operations is the fear and uncertainty regarding free gas behavior in marine risers. It is noteworthy (though beyond the scope of this article) that significant progress has recently been made that strongly suggests that MPD systems utilizing RCDs near the top of the riser can largely eliminate many hazards expected – or experienced – on rigs lacking the ability to close in and control annular flow. It may now be reasonably expected that EPWC benefits may be even greater on deepwater rigs with subsea stacks, perhaps substantially reducing their risks as well as operational costs. Given the range of potential benefits provided by MPD systems, even during non-drilling operations, as well as the close association between MPD operations and

primary well control objectives, it is thus proposed to introduce a new term that more clearly reflects an emerging truth: we now have tools available to radically improve our ability to maintain, monitor and precisely adjust downhole pressures. In other words, we now have the practical ability to improve or enhance primary well control. Systems with such capability could be referred to as “Enhanced Primary Well Control” (EPWC) systems, with MPD becoming just one of many operations enabled by use of such a system. While this may be a new term for the industry, it simply reflects a growing consensus regarding benefits that derive from the establishment of closed-loop operations, including, but not limited to MPD. Closedloop operations have become practical following, in particular, the development of annular control devices (i.e. RCDs), large bore automated drilling chokes, and precision flow meters (e.g. large Coriolis meters) field proven both on land and offshore.

ingly owned, maintained and operated by drilling contractors. This gives the rig EPWC functionality that will almost certainly “raise the bar” regarding operational capability (e.g. ability to deliver MPD if/as needed), efficiency (e.g. ability to quickly resolve and adjust primary well barrier is/as required), and most importantly, safety to personnel, equipment, and the environment. In a market with an overabundance of otherwise capable rigs, those with EPWC are likely to have a distinct marketing advantage. As more people consider, or experience the benefits of using MPD to manage many drilling events, it should become easy to see the full value of broadening the use of related closed-loop technologies to provide more reliable and efficient control during a wide range of well operations in which hydrostatic balance against formation pressure is either lost or simply uncertain. This wider application of EPWC concepts can, indeed, take us “beyond MPD”.

Importantly, such devices are becoming available as part of a rig’s preparation for potential MPD operations, and are increas-

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