MED OIL & GAS
Spring Magazine 2018 1
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Content
Features Comments by Elisabeth Tørstad CEO DNV GL Digital Solutions................................................................. 5 Societe Generale Corporate & Investment Banking- Oil Market Outlook.................................................. 6 FORCE Technology- Subsea Inspection of Tether String Welds................................................................ 15 DEA Norge- Utilizing Sea Floor Samples to De-risk the Petroleum System ............................................ 19 EBN Netherlands- Offshore potential and opportunities in the Netherlands . ........................................ 28 PKF Malta-Malta seeks investors for oil exploration .............................................................................. 35 Envoi Limited-International Exploration in the next cycle....................................................................... 39 Marex Marine- Role of the IMO in the Offshore Industry........................................................................ 47 Aarhus GeoSoftware- Inversion of Ground Conductivity Meter Data for Mapping of Raw Materials....... 51
Conferences........................................................................................................................................ 4, 47
Companies in the News STAUFF- portable filter unit for on-board hydraulics.............................................................................. 56 Koso Kent Introl- completes a major shutdown on a UK refinery ........................................................... 58 Liebherr Maritime Cranes-prepared for offshore challenges.................................................................... 61 Rotech Subsea- expands operations with a new office in Malaysia......................................................... 62 Equinor- offered licenses in the latest 24th licensing round ................................................................... 64 Tracerco- receives Lloyd’s Register recognition ...................................................................................... 68 Corvus Energy- provides energy storage for shore stations to charge electric ferries . ............................ 70
Published by: OYOMEDIA18 Limited, (MED OIL & GAS MAGAZINE is a subsidiary of OYOMEDIA18 Limited), Malta & Dubai Printed & designed by: Rosendahls a/s Denmark Cover photo Floriana, Malta overlooking Marsamxett Harbour
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CEO DNV GL Digital Solutions Digitalization has been embraced by the oil and gas industry for decades, with advanced big data analytics at the heart of exploration and production successes. Even so, I firmly believe that improved access to data and new digital technologies can represent another step change for the industry; providing longterm cost savings, enhanced operations and carbon footprint improvements. This view is widely shared amongst 800 top leaders that participated in a recent DNV GL survey; nearly half (49%) of respondents to the 2017 survey thought their own organizations needed to embrace digitalization to reduce costs and increase profitability. This year, that figure is 70%. The International Energy Agency (IEA) estimates that digital technologies could decrease upstream production costs by 10–20% with more advanced use of sensors, seismic data, and reservoir modelling. It also concludes that digitalization could increase technically-recoverable oil and gas resources by 5% globally. This step change is only possible with advanced use of data and by treating data as a valuable asset in itself – not only as a representation of assets. Considerable costs and efforts are incurred in collecting, storing, and acting upon data as a consequence of this. And in the same way that we understand the value chains of our business and
the production processes of bringing products to market, we must pay close attention to our data value chains. As any raw material, data is born, follows a value chain, and is then refined and prepared for different tasks. The user or the system that is utilizing the data does not necessarily have knowledge of the data origin, quality level, weaknesses, legal or contractual obligations, semantics, the system capturing data, the context in which the data was born etc. And data that is well suited for one type of analytics might therefore be not be well suited to combine with other data sets or used for other purposes.
Comments from Elisabeth Heggelund Tørstad Elisabeth.Torstad@dnvgl.com
In order to optimize the value creation from data and ensure valid analytics and good decisions, it is vital that we understand data quality in terms of consistency, semantics, context and compatibility. For us as business leaders, this is all about turning the raw material – your data – into a real asset. This means that we need to understand, manage and pay equal attention to this dimension of our operations as we do to our other raw materials and valuable assets. Only then can we harvest the significant opportunities that emerge from data availability and analytics.
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Societe Generale Oil Market Outlook K E Y P O I NT S • Price forecasts. We forecast front-month ICE Brent prices at $78 in 4Q18. We expect Brent to trade in a $65-85 range over the next 12 months. We forecast Brent at $75 for 2018 and $73 for 2019. For front-month NYMEX WTI prices, we forecast $73 in 4Q18. We expect WTI to trade in a $60-80 range over the next 12 months. We forecast WTI at $70 for 2018 and $68 for 2019. For both Brent and WTI, we are moderately bullish vs current front-month prices and forward curves. • Non-OPEC supply. For non-OPEC output plus OPEC NGLs, we project gains of 2.1 Mb/d in both 2018 and 2019, led by the US. US crude output growth should slow from 1.2 Mb/d in 2018 to 0.9 Mb/d in 2019; pipeline constraints and slowing well productivity gains are factors. • OPEC crude supply. Recent statements from Saudi Arabia and Russia indicate that OPEC and Russia may increase output by up to 1 Mb/d after the 22 June OPEC meeting in order to make up for actual losses from Venezuela and anticipated losses from Iran. We have factored in higher output, excluding those two countries, starting in 3Q18. However, the gains will be gradual and start out less than 1 Mb/d. The initial focus will be on making up for Venezuela. • Demand. We expect global oil demand to remain fairly healthy and project growth of 1.6 Mb/d in 2018 and 1.4 Mb/d in 2019. The main driver should be emerging markets, including China and India. However, growth should ease slightly in 2019 in emerging Asia and the US. • Inventories. With OPEC (excluding Venezuela and Iran) plus Russia eventually increasing supply by up to 1 Mb/d, overall OPEC crude output should stabilise. Following substantial OECD stockdraws in 2018, we project minimal stockbuilds in 2019. However, this year’s draws should provide ongoing price support next year, and this is the core of our moderately bullish price outlook. • Upside risks. The biggest upside risk would be if OPEC decides not to increase crude output in 3Q18 or increases it more slowly (10% probability, $10 crude price impact). • Downside risks. The biggest downside risks would be if OPEC increases more and faster than expected or if economic and oil demand growth sharply underperform (for both risks, 20% probability, $10 crude price impact).
World crude oil benchmarks ($/bbl)
Source: Bloomberg, SG Cross Asset Research/Commodities
6 | MED OIL & GAS | July 2018
ICE Brent forward curves ($/bbl)
Source: Bloomberg, SG Cross Asset Research/Commodities
ICE Brent short-term forecast vs forward curve ($/bbl)
Source: Bloomberg, SG Cross Asset Research/Commodities
Price forecasts: short-term crude oil through 2019 For our fundamental outlook this year and next, macroeconomic and product demand growth should be fairly healthy, although both should edge lower in 2019. On the supply side, non-OPEC production growth should continue to be very strong, led by the US, although the pace of US gains should be moderately slower in 2019. The biggest change is expected in OPEC supply. OPEC and Russia are expected to substantially increase output beginning in 3Q18, by as much as 1 Mb/d, in order to offset losses from Venezuela and the expected impact of oil sanctions on Iran. There also appear to be concerns about Brent prices moving above $80. The additional crude from OPEC (excluding Venezuela and Iran) means that overall OPEC crude output should stabilize. The result will be that, in contrast to this year, when global stocks are expected to draw by 0.3 Mb/d, global stocks should build by 0.4 Mb/d in 2019. Looking at the OECD, following substantial draws in 2018, there should be minimal builds in 2019. This year’s OECD draws should provide ongoing price support next year, and this is the core of our moderately bullish price outlook relative to current front-month prices and forward curves (see charts above). We forecast front-month ICE Brent prices at $80 in 3Q18 and $78 in 4Q18. We expect Brent to trade in a $65-85 range over the next 12 months. On an annual basis, we
ICE Brent long-term forecast vs forward curve ($/bbl)
Source: Bloomberg, SG Cross Asset Research/Commodities
forecast Brent at $75 for 2018 and $73 for 2019. For front-month NYMEX WTI prices, we forecast $75 in 3Q18 and $73 in 4Q18. We expect WTI to trade in a $60-80 range over the next 12 months. On an annual basis, we forecast WTI at $70 for 2018 and $68 for 2019. For both Brent and WTI, we are moderately bullish vs the forward curves. Our base-case crude price forecasts should be considered as the centre points of $10wide trading ranges. In other words, crude prices may routinely trade $5.00 above or below our forecasts, based on normal volatility, driven by fundamental developments, including seasonal changes, non-fundamental factors such as investor flows, and geopolitical developments.
NYMEX WTI vs ICE Brent We project that in 2H18 and 2019, NYMEX WTI should trade at an average discount of $5 to ICE Brent. We view this as the centre of a wide and volatile range, with the discount between $3 and $7 most of the time. Recent WTI discounts in the $8-9 range are seen as unsustainable and do not appear to be based on any fundamentals. Looking ahead, the fluctuations should depend on the physical crude balances in the US relative to the physical crude balances in Europe and Asia; key factors include relative crude stocks and refinery crude runs. The WTI vs Brent discount should – on balance – incentivise US crude exports, which should continue to increase in line with growing US crude production. We note that with WTI vs Brent at -$5 and Dubai vs Brent at -$3
to -$3.50, WTI’s discount to Dubai is forecast at -$1.50 to -$2.00, which should be wide enough to incentivise ongoing US crude flows to Asia. These volumes have become as important as US crude flows to Europe.
Crude timespreads The “OPEC supply management” statistical relationship between OECD days forward cover and crude timespreads reasserted itself over the June 2017–April 2018 timeframe. Assuming that this relationship holds, our fundamental outlook, as summarised in our OECD days forward cover forecast, indicates that one-year forward Brent timespreads should remain firmly in backwardation in 2H19 and 2019. OECD days forward cover is forecast to drop to 56-57 days, which would be four to five days below the five-year average. This implies that one-year forward Brent timespreads should strengthen to $10-12. This compares to backwardation in the $5-6 range for April and much of May, though it has fallen below $4 in the last two weeks.
Price risk highlights Our most extreme upside price risk is if OPEC decides not to increase crude output in 3Q18 or increases output significantly more slowly than expected. If this were to materialise, we would expect to see crude prices $10 higher than our base case. We assign a 10% probability to this risk. Our two most extreme downside price risks follow here. The first is if OPEC increases crude output significantly more than expected and/or significantly faster than ex-
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pected. The second is if economic and oil demand growth sharply underperform expectations. If either of these were to materialise, we would expect to see crude prices $10 lower than our base case. We assign a 20% probability to both of these risks.
Price forecasts: short-term refined products through 2019 Product cracks and refining margins in the US, Europe and Asia should continue to be healthy in 2H18 and 2019. The key factors are expected to be solid product demand growth and continued high refinery utilisation rates.
Focus on IMO 2020 low sulphur shipping fuel requirement However, the main story for product markets in the second half of next year, and probably for the entire global crude and product complex, is that the oil markets will start to become very focused on the 1 January 2020 implementation of the new International Maritime Organisation (IMO) low sulphur requirements (0.5%) for global shipping fuel. This will have major impacts on the product markets, with significant knock-on effects on crude. The peak market impact is expected to be in 2020, with the shipping industry and refining sector continuing to adjust in the following years.
Strength in distillate demand and distillate cracks Around 3 Mb/d of high sulphur fuel oil demand (HSFO) will be lost initially. It will be
mainly replaced by distillate demand (marine diesel), at least through 2020. This will cause distillate cracks to increase sharply. HSFO cracks will collapse, and low sulphur fuel oil (LSFO) cracks will also weaken, but not quite as much as HSFO, meaning that LSFO vs HSFO spreads should widen. More specifically, in 2H19, as the markets prepare for the transition to low sulphur shipping fuel, distillate cracks should strengthen dramatically due to the massive incremental demand, with increases continuing into 2020. We forecast ICE gasoil cracks vs Brent to increase to $15 in 3Q19, $20 in 4Q19, and $25 in 2020 (annual average). Over the same timeframe, we project NYMEX ULSD cracks vs LLS to increase to $20, $25 and $30, respectively. For Singapore gasoil 0.05% cracks vs Dubai, we forecast increases to $17, $22.50 and $27.50, respectively.
Upward pressure on sweet crude prices We believe the extraordinary strength in distillate cracks will cause refiners to run as hard as they can, and this very strong crude demand will add $5 to sweet crude prices – including WTI and Brent – beginning in 4Q19 (relative to where they would have been otherwise). Sweet (low sulphur) crude will be at a premium because minimising sulphur is the issue for refiners. The sweet crude price uplift from very strong distillate demand growth and cracks should continue in 2020, and this is the reason for our upward crude price forecast revision in that year (see long-term crude price forecasts below).
Non-OPEC supply growth by region, 2017-2019 (yoy)
Source: History – IEA; forecast - SG Cross Asset Research/Commodities
8 | MED OIL & GAS | July 2018
Downward pressure on sour crude prices The discount for sour (high sulphur) crude will increase because demand will be lower. Also, sour crude prices tend to move in line with fuel oil prices because they yield a much higher proportion of fuel oil when processed in a refinery (i.e., fuel oil cracks and sour crude discounts tend to strengthen and weaken together). We forecast that Dubai vs Brent should weaken from -$3.50 in 2H19 to -$6 in 2020. Our full set of detailed regional refined product price forecasts is included in the tables at the front of this report. Focusing on proxies for refining margins in the US, we expect 3-2-1 cracks vs LLS to increase from $15.15 in 2018 to $16.35 in 2019 and $19.35 in 2020. In Europe, our forecasts are for 5-2-2-1 cracks vs Brent to increase from $6.15 in 2018 to $7.50 in 2019 and $11.20 in 2020.
Price forecasts: long-term crude oil 2020-2023 As noted above, the new IMO low sulphur shipping fuel requirements will boost sweet crude prices due to very strong distillate demand growth and cracks. As a result, our forecast for ICE Brent in 2020 has been revised $5 higher to $70. For 2021 and 2022, our Brent forecast is unchanged at $65, and we maintain this level for 2023. The rationale for our long-term price view has not materially changed. In effect, we are
US crude output growth by region, 2015-2019 (yoy)
Source: History – US EIA; forecast - SG Cross Asset Research/Commodities
saying that a $60-70 world will be enough to incentivise the projects and investments needed to bring on new supply. The argument has three main components, all of them inter-related. We repeat this analysis from the last quarterly Commodities Outlook. First, although medium-cost US shale oil will meet most global demand growth this year and next year, when we move to a five-year time horizon, there will be an eventual need for high-cost crude from deepwater offshore and Canadian oil sands. While the required volumes of high-cost crude have been coming down in the last couple of years, significant increments are still needed. Second, the costs of “high-cost” crude have been declining in the last three years (20152017). Though the reductions have not been quite as dramatic as the 35% reduction seen for US shale development costs, Canadian oil sands development costs have been reduced to $60 for mining projects, and lower for in-situ development (SAGD). Deepwater offshore costs for areas such as Brazil, West Africa, and the US Gulf of Mexico have also been reduced to the mid-$50s or lower. This means that a $60-70 world should be enough to incentivise producers to make the investments required to bring on supply from these sources. The pace of project announcements started to increase in 2017, relative to the previous two years, and we expect this to continue. Third, producers have changed their upstream strategies to emphasise a shorter cycle and more flexible and cheaper investments, putting into practice the lessons learned from US shale producers. This means that producers are focusing mainly on cheaper and faster expansions of existing projects rather than more expensive and lengthier new greenfield projects. For Canadian oil sands, this means growth from expansions of existing mining projects and lower cost in-situ projects rather than large new mining projects. For deepwater offshore, while some large new fields are planned, producers are more focused on expanding existing fields, exploiting smaller satellite fields and generally maximising the utilisation of existing infrastructure.
Supply – Non-OPEC: strong growth in 2018 and 2019, led by US For non-OPEC output plus OPEC NGLs (i.e., all global supply except OPEC crude), we project steady overall gains of 2.08 Mb/d in 2018 and 2.11 Mb/d in 2019, led by the US (see chart below left). As discussed below, the pace of US growth is expected to slow next year, but slightly higher gains from various regions should offset this. Notably, significant growth is expected in 2019 from Canada, Brazil, Kazakhstan and Russia. Russian output increases are anticipated to gradually begin in 3Q18, in line with higher OPEC production (see OPEC section below). In 1H17, over the course of several months, Russia cut crude production by 300 kb/d, in cooperation with OPEC. Based on market reports and industry sources, we believe it will take Russia two to three months to fully recover these volumes. US production continues to be the most important driver for non-OPEC supply as a whole. Driven by shale oil, particularly from the Permian Basin in West Texas, we forecast growth in US crude output of 1.22 Mb/d in 2018; however, growth is expected to slow to 0.91 Mb/d in 2019 (see chart above right). Our US crude growth forecasts continue to be on the conservative side of the spectrum, and we’ve revised our 2018 outlook down slightly by 40 kb/d. In addition to increasing crude volumes, US NGLs output should gain 0.44 Mb/d in 2018 and 0.39 Mb/d in 2019. Adding crude and NGLs together brings total US liquids growth to 1.65 Mb/d in 2018 and 1.30 Mb/d in 2019. The capital spending environment hasn’t changed materially, with moderate increases of 10% or less planned for this year. For producers, the story of “living within cash flow” continues to be dominant. Many producers have indicated that they expect excess cash flow, which they intend to use to strengthen their balance sheets, increase dividends or buy back shares. The reasons for our conservative view on US crude output growth this year, and for a slowdown in growth next year, are continuing service sector constraints, pipeline constraints that have emerged in recent months and some preliminary reports of slowing well productivity gains.
Oilfield service sector constraints continue to be a factor in shale oil production, as evidenced by ongoing increases in drilled but uncompleted (and unfracked) wells (DUCs). The availability of fracking and completion crews remains tight and continues to be an issue. The pipeline constraints are caused by limited takeaway capacity out of the Permian Basin to handle quickly growing crude output. Aside from anecdotal evidence, such as reports from producers and pipeline operators, the best evidence for these constraints has been weakening crude price differentials for WTI Midland relative to WTI Houston and WTI Cushing. Significant new pipeline capacity from the Permian Basin to the USGC is planned, but most of it will not come onstream until 2H19. This should relieve the constraint at that point, but until then, WTI Midland prices are expected to continue to be under pressure. We expect most of the impact of this to be in a slowing rate of crude output growth, from 2H18 onwards. Drilling activity may not slow up much, but the number of DUCs should increase and the pace may accelerate. Finally, just in the last month or two, we have started to see some early reports from various industry sources, including Platts (oil trade press), that the rate of growth in productivity per well may be starting to slow up. This is reportedly due to some producers (generally not the largest investment grade companies) starting to drill wells outside their most productive core areas, in more mature shale plays. In other words, the long and gradual shift from Tier 1 to Tier 2 targets may be beginning. We expect this process to take years to unfold, but it is noteworthy because until recently, we have not seen such reports. If the growth in productivity per well is starting to slow, this would have a direct impact on the rate of overall US production growth.
Supply – Overall OPEC output expected to broadly stabilise Statements in the past week from Saudi Arabia and Russia indicate that OPEC and Russia may increase output by up to 1 Mb/d after the 22 June OPEC meeting in order to make up for actual losses from Venezuela and anticipated losses from Iran (see chart below left for recent OPEC crude output, which has been pulled down by Venezuela). We have factored in higher output, exclud-
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OPEC crude output 2016-2018
Source: IEA, Reuters, SG Cross Asset Research/Commodities
ing those two countries, starting in 3Q18. However, the gains will be gradual and start out less than 1 Mb/d. At this point, we only have several comments from the Saudis, Russians and others in OPEC that indicate both an intent to make up for supply losses and concern over a potential surge in Brent prices above $80 if this were not to happen. While these statements have been generally consistent – at least on making up for Venezuela and Iran, if not on prices – details will not be hammered out until the next OPEC meeting on 22 June. Until then, there is ample room for interpretation. We make several key points that clarify our current take on the situation. First, we do not expect overall OPEC output to increase by up to 1 Mb/d. We expect OPEC excluding Venezuela and Iran to increase by up to 1 Mb/d; declines in Venezuela and Iran are still expected. For reasons discussed in other reports, the Venezuelan collapse has caused output to decrease by over 600 kb/d since 3Q17 (see chart below right). We forecast production to continue to decline by 50 kb/d per month through the rest of 2018 and all of 2019. This averages out to a sequential drop of 150 kb/d per quarter. On an annual average basis, we forecast Venezuelan crude to drop from 1.97 Mb/d in 2017 to 1.30 Mb/d in 2018 and 0.70 Mb/d in 2019. Regarding the impact of oil sanctions on Iran, as we have also analysed in detail in various other reports, we project eventual losses at 0.4-0.5 Mb/d. These should take place gradually between now and November, when the sanctions come fully into effect. 10 | MED OIL & GAS | July 2018
OPEC crude output 2016-2018 – focus on Nigeria/Libya/Venez
Source: IEA, Reuters, SG Cross Asset Research/Commodities
Second, the increase from OPEC and Russia will be gradual, careful and cautious. The Saudis have repeated that they want to stabilise supply, but they do not want to shock the market. We believe the focus will be more on replacing Venezuelan losses and less on offsetting the impact of Iran sanctions, simply because the size of the impact on Iran is not yet known. Third, the immediate response in OPEC is expected to come mainly from Saudi Arabia, Kuwait and the UAE. We expect “core OPEC” to increase by 500 kb/d. No one else in OPEC has any significant immediately available spare capacity. As discussed above, we also expect Russia to increase gradually, by 200 kb/d within two to three months. Both core OPEC and Russia could increase further, but we don’t think they will do so right away and will wait to see if it is needed or not. In addition to the 700 kb/d above, we expect Angola to gradually increase output by 200 kb/d starting in 4Q18 due to the 3Q18 start-up of the deepwater offshore Kaombo field. Finally, we anticipate that Iraq will be able to increase output from the Kurdish regions in the north by 275 kb/d (the current shut-in volumes) beginning in 1Q19. This will depend on agreement between the federal government and the Kurdish regional government (KRG); however, following the recent elections in Iraq, a lengthy coalition building period to form a government is expected, and this is expected to delay a revenue-sharing agreement with the KRG until the beginning of 2019. When the immediate increases from core OPEC are added to the later increases from
Angola and Iraq, and when expected declines from Venezuela and Iran are factored in, the net result is that total OPEC crude output is forecast to broadly stabilise at 31.7–31.9 Mb/d between 3Q18 and 3Q19, before dropping to 31.6 Mb/d in 4Q19. It is therefore important to remember that while all the headlines will be about an OPEC increase, for now, we believe that the net result will simply be stabilisation. That said, steady OPEC output in 2019 vs 2018 will play an important role in moving the global markets from deficit to surplus next year. A final point to emphasise is that this output adjustment is just that and nothing more. It does not mean an end to either OPEC-Russia supply management or OPEC-Russia cooperation. We expect both to continue for the foreseeable future.
Demand: solid global growth in 2018 and 2019 We expect global oil demand to remain fairly healthy and project growth of 1.6 Mb/d in 2018 and 1.4 Mb/d in 2019. While SG’s macro team expects a minor slowdown in global GDP growth from 3.9% this year to 3.7% next year, this is still a fairly healthy environment. More to the point, the slower growth is mainly in the US and advanced economies. This shouldn’t have much of an effect on emerging markets, which – as usual – are expected to be the key driver for oil demand growth (see chart p.11 to left). We project non-OECD growth at 1.20 Mb/d in 2018 and 1.15 Mb/d in 2019. We forecast Chinese demand growth of 470 kb/d in 2018 and 400 kb/d in 2019. Other emerg-
Global product demand growth – by region, 2017-2019 (yoy)
Source: History – IEA, forecast - SG Cross Asset Research/Commodities
ing Asia, which includes India, is expected to contribute 440 kb/d in 2018 and 400 kb/d in 2019. Part of the reason for the easing growth in China and other emerging Asia is simply that we consider a slightly slower pace more sustainable. In addition, we are conscious of the possible impact that higher prices may have on dampening growth in China and India. In China, product prices are very close to global market prices. In India, product price subsidies have been sharply reduced in recent years, making consumption more vulnerable to higher prices. We also expect OECD demand to grow by 410 kb/d in 2018 and 240 kb/d in 2019. The slower OECD demand growth in 2019 is responsible for most of the slower rate seen globally. Within the OECD, US growth is forecast at 360 kb/d in 2018 and 250 kb/d in 2019. The US gains in both years should
Source: industry sources, SG Cross Asset Research/Commodities
be driven by hydrocarbon gas liquids; these HGL increases should in turn be caused by an increase in ethylene-producing petrochemical plants that use ethane as a feedstock. As in emerging Asia, we are alert to the possible negative impact of higher prices on demand growth in the US, particularly for gasoline; however, this is not explicitly factored in at this point.
Seasonality: typical 3Q crude price strength expected this year In the third quarter, the typical seasonality is for stronger crude demand, due to peak summer refinery runs, and stronger product demand, due to peak summer driving consumption (in the northern hemisphere). This seasonality is demonstrated on the chart
Global refinery runs: Jun vs May +1.4 Mb/d; Jul vs Jun +0.9 Mb/d; Aug vs Jul +0.0 Mb/d
Source: IEA, SG Cross Asset Research/Commodities
Global product demand growth – by product, 2016-2019 (yoy)
below, which shows the current outlook for global refinery crude runs (i.e., crude demand). From the current month of May to the summer peak in July and August, global runs are forecast to increase by 2.3 Mb/d, of which 1.4 Mb/d in June vs May and 0.9 Mb/d in July vs June. In 3Q18 and 4Q18, even though OPEC excluding Venezuela and Iran will be producing more crude, global markets will still be drawing slightly, and OECD stocks should be drawing by 0.3 Mb/d and 0.5 Mb/d, respectively. This will maintain upward pressure on crude prices and is consistent with the seasonal peak in crude demand in the third quarter.
Inventories: significant OECD stockdraws in 2018, minimal OECD stockbuilds in 2019 Here, we put the pieces of the supply-demand balances together. As shown on the summary balances table below, global stocks are projected to draw by 0.30 Mb/d in 2018 but build by 0.36 Mb/d in 2019. OECD stocks are forecast to draw by a significant 0.46 Mb/d this year but build by a minimal 0.16 Mb/d next year (see chart p12 top left). It should be noted that OECD stocks are “tighter” than global stocks because we assume non-OECD stockbuilds of 0.2 Mb/d; the latter includes the Chinese SPR, as well as non-discretionary builds associated with new infrastructure (such as refineries, pipelines, and storage facilities). It should be 11
OECD crude and product stocks – days forward cover
(OECD days forward cover vs 5y average) vs ICE Brent 1y forward timespreads
Source: History – IEA, forecast - SG Cross Asset Research/Commodities
further noted that OECD stocks have timely and accurate reporting, and they therefore play a bigger role in driving the global markets. In particular, statistical analysis shows that they are important for crude timespreads. The minimal stockbuilds next year mean that this year’s draws should continue to provide price support, and downward price pressure will have only a limited effect. In
Source: Bloomberg, IEA, SG Cross Asset Research/Commodities
other words, the substantial 2018 OECD stockdraws are the key factor driving our moderately bullish crude price outlook all the way through 2019. As shown in the chart above right, the “OPEC supply management” statistical relationship between OECD days forward cover and crude timespreads that existed between January 2008 and October 2014 reasserted itself over the June 2017–April 2018
timeframe. Assuming that this relationship holds, our fundamental outlook, as summarised in our OECD days forward cover forecast, indicates that one-year forward Brent timespreads should remain firmly in backwardation in 2H19 and 2019. OECD days forward cover is forecast to drop to 56-57 days, which would be four to five days below the five-year average. This implies that one-year forward Brent timespreads should strengthen to $10-12. This compares to
Oil supply, demand, and price forecast tables SG short-term oil supply, demand and price forecasts Mb/d
2017
1Q 18
2Q 18f
3Q 18f
4Q 18f
2018f
1Q 19f
2Q 19f
3Q 19f
4Q 19f
2019f
OECD demand
47.4
47.6
47.4
47.9
48.3
47.8
47.7
47.7
48.1
48.5
48.0
Non-OECD demand
50.4
50.5
51.9
51.8
52.0
51.6
51.8
53.1
52.9
53.1
52.7
World demand
97.7
98.1
99.3
99.6
100.3
99.3
99.5
100.8
101.0
101.6
100.7
*Non-OPEC supply
58.3
59.2
59.9
60.6
61.3
60.3
61.4
61.9
62.4
63.0
62.2
6.9
6.9
6.9
7.0
7.0
7.0
7.1
7.1
7.2
7.3
7.2
*OPEC NGLs *OPEC crude
32.3
32.0
31.7
31.9
31.7
31.8
31.9
31.7
31.8
31.6
31.8
World supply
97.5
98.1
98.5
99.5
100.0
99.0
100.3
100.8
101.4
101.9
101.1
-0.2
0.0
-0.8
-0.1
-0.3
-0.3
0.8
-0.1
0.4
0.3
0.4
NYMEX WTI ($/bbl)
50.95
62.87
70.78
75.00
73.00
70.41
68.00
65.00
68.00
70.00
67.75
ICE Brent ($/bbl)
54.83
67.18
76.25
80.00
78.00
75.36
73.00
70.00
73.00
75.00
72.75
Stock change
Source: Historical data – IEA; forecasts – SG Cross Asset Research/Commodities. Note: IEA historical data from 16 May 2018 monthly Oil Market Report (OMR). *Non-OPEC supply includes processing gains and biofuels.
SG long-term oil price forecasts 2016
2017
2018f
2019f
2020f
2021f
2022f
2023f
WTI NYMEX ($/bbl)
43.32
50.95
70.41
67.75
65.00
60.00
60.00
60.00
Brent ICE ($/bbl)
45.04
54.83
75.36
72.75
70.00
65.00
65.00
65.00
Source: Bloomberg, SG Cross Asset Research/Commodities
12 | MED OIL & GAS | July 2018
backwardation in the $5-6 range for April and much of May, though it has fallen below $4 in the last two weeks.
Upside risks Key upside risks include the following: • OPEC decides not to increase crude output in 3Q18, as we assume, or increases it significantly more slowly. Another possibility is that, given all the other geopolitical risks, when OPEC increases, the market decides to focus on lower remaining spare capacity rather than higher output.10% probability, $10 crude price impact. • Crude production in Venezuela is significantly lower than we forecast. The impact of oil sanctions on Iran is significantly bigger than expected (i.e., more crude is taken off the market). European imports from Iran drop by significantly more than our base case 50%, and China decides to cooperate with the US and cut some imports because US-China trade tensions ease (our base case is that China does not cut at all). Supply disruptions elsewhere increase from countries such as Libya and Nigeria. Other geopolitical risks include Saudi Arabia vs Iran in Yemen and Israel vs Iran in Syria. 30% probability, $5 crude price impact. • US crude output surprises to the downside due to pipeline constraints being more severe than we currently assume. 20% probability, $5 crude price impact. • The upward pressure on light sweet crude prices related to the new IMO shipping fuel specs is stronger than expected. 50% probability, $5 crude price impact.
Downside risks Key downside risks include the following: • OPEC decides to increase output significantly more than we assume or significantly more quickly than we assume. 20% probability, $10 crude price impact. • Production in Venezuela declines significantly more slowly than we assume or even stabilises.10% probability, $5 crude price impact.
• The impact of oil sanctions on Iran is less than expected (i.e., less crude is taken off the market); European imports drop by significantly less than our base case 50% as European oil companies feel protected from US sanctions by EU “blocking legislation”. 15% probability, $5 crude price impact. • US crude output surprises to the upside despite pipeline constraints, the pipeline constraints are not as severe as we assume, or pipeline capacity additions are brought on sooner than expected; current plans are for 2H19. 20% probability, $5 crude price impact. • The upward price pressure on light sweet crude prices related to the new IMO shipping fuel specs is less than expected. 25% probability, $5 crude price impact. • Macroeconomic and oil demand growth is significantly less than expected. Specific macro risks, with probabilities ranging from 15-25%, include a European policy uncertainty shock, protectionism and trade wars, a sharp market repricing and a hard landing in China. 20% probability, $10 crude price impact. • Net length for ICE Brent and NYMEX WTI remains high even after a moderate sell-off in recent weeks, so they are still vulnerable to profit taking and liquidation. The backwardation and positive roll yield, as well as the use of oil as a hedge against inflation, have been the two main rationales for investors. With OPEC poised to increase output and a more balanced market expected next year, the backwardation argument, which depends on stockdraws, may be challenged. Having said that, the high level of geopolitical risk and the expected reduction in spare capacity with higher OPEC output argue against too much of a reduction in net length. 20% probability, $5 crude price impact.
Extreme price scenarios: what would it take to see $100 Brent? $60 Brent?
time. An example would be that OPEC does not increase output as expected and production in Venezuela and Iran is lower than expected and US crude supply surprises to the downside. Similarly, in order to see Brent at $60, we would need to see several downside risks taking place at the same time. An example would be that OPEC increases output more than we assume and production in Venezuela and Iran is higher than expected and US crude supply surprises to the upside. In addition, this would need to happen at the same time as slower economic growth has a negative impact on demand growth. Since last week, when Saudi Arabia and Russian clearly signalled their intent to increase crude production to offset losses from Venezuela and the expected impact of oil sanctions on Iran, the market’s view or perception is that the probability of $100 Brent has decreased and the probability of $60 Brent has increased. Compared to our expected trading range of $65-85 for Brent over the next four quarters, $65 appears to be more likely and less of an extreme scenario.
This outlook was originally published by Societe Generale on 31 May 2018.
Author Mike Wittner Societe Generale Managing Director Global Head of Oil Research michael.wittner@sgcib.com
In our view, in order to see Brent at $100, we would need to see a combination of several upside risks taking place at the same
13
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SUBSEA INSPECTION OF TETHER STRING WELDS This paper describes technologies, methods and results of Automated Subsea Inspection of Tether String Welds, and provides valuable information, enabling our customers the correct and beneficial choice of method for scanning Tether String Welds.
Abstract Life extension of offshore platforms and change/increase of loads at the platforms has led to increasing requirements for documentation of the condition of the welds. FORCE Technology has performed Subsea Inspection of Tether String Welds for more than 10 years, and hence contributed to the safe operation of several platforms. The fast growing demand for accurate and professional scan methods, as well as detailed documentation of Tether String Welds’ conditions, drive continuous improvement of existing technologies and development of new tools to meet customers’ needs.
Introduction Experienced in Tether Weld Inspections FORCE Technology has carried out inspection of welds at Tethers since 2003 at the Norwegian “Heidrun” platform, since 2007 at the Norwegian “Snorre A” platform, and in 2012 at the “Jolliet” platform in the Gulf of Mexico. With the increasing need for our services within Tether Weld Inspections, cooperation with local companies in The US, Africa and Middle East has enabled significant service improvement to customers in these regions. Subsea inspection of Tether String Welds Tension Leg Platforms (TLP’s) are floating platforms which are held in position by Tethers. These tethers are made of welded pipe with anchors at each end to connect to base plate and platform. The dimension of
the pipe and length depends on the size of the platform and water depth.
History of Subsea P-scan FORCE Technology developed the first diver operated Subsea Ultrasonic inspection system in the mid 80’es and requirements for performing inspection at deeper waters. This led in the late 90’es to the development of the first ROV operated system enabling Subsea Inspection depths of 1000 m. The Subsea inspection tool is based on the P-scan system which is an automated Ultrasonic and Eddy Current Inspection system. The P-scan system is a computerized Ultrasonic System for automatic, mechanical or manual ultrasonic inspection of welds and materials, developed by FORCE Technology. Through regular use in the industry, for applications in power plants (conventional, nuclear, wind), Offshore industry, Chemical
Industry, Refineries, Shipbuilding etc., valuable experience is collected. The P-scan system has documentation and storage facilities for all data related to each inspection operation, including visualization of the inspection results in the form of images of the material volume examined. Storage sources are hard disk, USB stick, optical disk and more.
Excellent Data and Images The P-scan system provides A-scan, B-scan, C-scan, T-scan (thickness mapping) and TOFD (time-of-flight diffraction) mode, including averaging for sizing of defects. Furthermore, the system provides projection images of the object under examination, e.g. images of the weld or part of an object. In the three projection images, called TOP, SIDE and END views, the flaws which have been detected are automatically shown at their correct location. 15
Capability The Subsea Inspection system has at least the same capability as the inspection system used for the original inspection during production. The inspection system has 16 ultrasonic channels which can be fitted with any type of ultrasonic probe, shear wave, compression wave, creep wave or TOFD. The probes can be combined arbitrarily as required by the inspection procedure. The inspection system allows for addition of up to 8 Eddy Current channels.
Equipment used Subsea Scanner The base of the inspection system is the magnetic wheel scanner which can be configured for numerous applications. The scanner is fitted with powerful permanent magnetic wheels, allowing it to cling on to any steel surface including coating. The wheels are mounted in a boogie setup, giving the scanner a small foot print on the surface to be inspected and allowing the scanner to be easily steered remotely.
Example of data presentation in P-scan
For sideways movement of probes, the scanner can be fitted with tracks of different length from 250 mm and upwards. Standard length is 500 mm.
The tool skid must be supplied with AC power and hydraulics for reeling in and out the umbilical. For communication and data transmission, a single mode fiber is used, leading through the ROV.
The current Subsea Scan system is pressure tested down to 1000 m water depth.
It has a docking bay for the scanner which contains a reference plate, enabling calibration at the actual depth of the inspection.
Inspection of welds
Inspection Setup A typical setup for inspection of welds consists of a detection setup with 2 sets of shear wave probes, 1 set focused on the inner surface and 1 set focused on the outer surface. The probes are placed on each side of the weld. The figure below shows a setup with 60ยบ probes focused on the inner surface and 45ยบ probes focused on the outer surface utilizing the reflected beam.
Tool Skid
Purpose
Procedure
A tool skid has been developed for housing of the inspection system. The tool skid is designed to fit under a working class ROV and is made flexible to fit with any brand of ROV. The tool skid houses an electronics bottle with the P-scan system, an umbilical to the scanner and the scanner with probes and cameras.
The main purpose of the inspection is to verify that no service induced indications are present in the welds. Welding defects can also be detected but it is normally assumed that their size is below the original acceptance criteria and therefore shall not be taken into consideration during development of an inspection procedure.
The welds are always subjected to tension normal to the weld. The magnitude of the tension varies with the load on the platform and the wave height. The inspection procedure is therefore developed with focus on detection and sizing of indications parallel to the weld, and breaking either the inner or the outer surface. The inspection procedure
Subsea Scanner
16 | MED OIL & GAS | July 2018
Tool Skid
does not include inspection for indications normal to the weld. Time of Flight Diffraction technique (ToFD) For sizing is used Time of Flight Diffraction technique (ToFD) with 1 set focused on the inner surface and 1 set focused on the outer surface. The figure below shows a setup with 45ยบ probes focused on the inner surface and 60ยบ probes focused on the outer surface.
Example of Pulse-Echo probe setup
Example of ToFD setup
If the weld cap has been ground flush, a normal probe can be added to the detection setup. Additionally an Eddy Current probe can be added to increase the sensibility for detection of outer surface breaking indications. In order to ensure full coverage of the weld and heat affected zone, the whole probe setup is transversed.
Qualification of inspection system Full-size mockup qualification When required by the customer the inspection system is qualified on a full-size mockup. The mockup is made of identical materials and welded with the same procedure as the actual tether strings. In the weld and heat affected zone is machined a number of representative notches with different dimensions in order to verify the sensitivity of the inspection system.
Test of ROV system in lab tank
Test of scanner handling on deck
Further requirements Topside Control room
FORCE Technology has the facilities to qualify the inspection system under realistic conditions with a large water tank and overhead crane for hoisting mockup and inspection system into position.
Inspection on-site Inspection of welds on TLP tethers are normally carried out from a ROV, it can be carried out by divers if only the welds in shallow waters shall be inspected. Larger platforms has a ROV stationed on the platform on smaller platforms a diving vessel with ROV is required. The inspection tool skid is mounted under the ROV and communication established through the ROV umbilical. Function tests are carried out on deck so the ROV crew can train the handling of the scanner.
Topside, a room for the Control Unit is required, with Communication, Video recorder and PC. 2 monitors are used to monitor the video cameras, scanner steering and data collection.
Scanning on Tether weld
Decision criteria The selection of welds for inspection is normally carried out by the owner of the offshore construction. The decision is based on the loads on the Tether Strings and history, if any of the Tethers have been exposed to stress larger than normal, or records show that welding defects close to the original acceptance criterion is present in the welds.
Reporting On-site reporting is provided so a preliminary report is handed over before the
FORCE Technology inspection crew leaves the platform. Findings above the specified acceptance criteria are reported within 24 hours of the discovery.
Development of new technologies FORCE Technology has an in-house development department with substantial capacity within mechanics, electronics and simulation which allows continuous adaptation and construction of new inspection systems for a broad variaty of applications. 17
The data achieved through FORCE Technology Subsea Inspections is state of the art and provides excellent base for beneficial decisions for offshore structure owners. FORCE Technology participates in projects involving extensive specialised knowledge, from the initial concept until delivery of the turnkey project. At completion we document that the customer will gain the expected functionality, efficiency and value-generation.
Calibration
Marine growth removal
Conclusions
To ensure that inspection of welds can be carried out fast and without interruptions, the marine growth must be cleaned off the weld and the area where the scanner will operate. Usually this is 200-300 mm on each side of the weld.
The FORCE Technonlgy Subsea Inspection system has over a decade proven to perform valuable inspection on various Tether String Welds and has at least the same capability as the inspection system, used to perform inspection during production.
Calibration
The inspection system is fitted with 16 Ultrasonic channels which can be fitted with any type of Ultrasonic probe, shear wave, compression wave, creep wave or TOFD. The probes can be combined arbitrarily as required by the inspection procedure. The inspection system also allows for addition of up to 8 Eddy Current channels.
The tool skid is fitted with a bay with a reference plate so calibration can be carried out at the working depth. This is to ensure that the correct reference is used during inspection of the welds.
Experience the progress.
offshore.crane@liebherr.com facebook.com/LiebherrMaritime www.liebherr.com
Author Ole Nørrekær Mortensen Business Manager – Advanced NDT Global FORCE Technology
UTILIZING SEA FLOOR SAMPLES TO DE-RISK THE PETROLEUM SYSTEM A Case Study from Mid Norway
Introduction DEA Norge was exploring a stratigraphic play offshore in the Norwegian Sea and set out to rank prospects using a seabed sediment samples. In order to do so, DEA Norge undertook a geochemical and geomicrobial survey in 2012-13. Due to the inconclusive nature of the results, a denser grid of seabed samples was collected the following year. Sampling also included data from reference wells within the license (Figure 1) and nearby discoveries. The intention of the study was to perform a DFI risk update in light of this new information. However, we conclude that it is more reasonable to use the results presented here to de-risk the total Petroleum System, due to ambiguities associated with lateral migration. We identified complex interrelationships between anomalies and the underlying petroleum system. Though direct, prospect-scale correlations were identified locally, we concluded that the potential of the results Jay mainly in de-risking the total petroleum system due to correlative ambiguities arising from lateral migration, which cannot exclude a direct source signal. Samples from the nearby gas/condensate discoveries seemed to map the reservoir charge directly from below. Samples from within the license show condensate/oil anomalies although they are officially classified as either dry (Hans) or as small gas
Figure 1: Traffic light classification of seafloor samples used and N-S seismic line across prospect . MPOG anomalies plotted as circles on top of the seismic line. The Hans Well is displayed with FIS data. Note that FIS anomalies are associated with distinct intervals that can be traced laterally (for final interpretation see Figure 3). Data courtesy of TGS and FIT.
discovery (Fritz) suggesting that anomaly geometry being moderated by fault conduits in the overburden (Figures 1&2). The prospect seems to be a combination of vertical seepage, whilst a part of the signal is transported laterally. We distinguished the prospect specific signal by using calibration wells in the area and carefully reviewing seismic sections with coring positions to “trace� the signal. The data collected over the prospect (Figure 1) are more oil prone
signal with respect to the reference wells, which are gas prone (Figure 2).
Method Gravity core samples of seabed sediments were acquired for laboratory analysis in 2012 on a nominal l km grid taking in the stratigraphic prospects, adjacent deeper basin and basin margin zones, plus the Fritz (gas) and Hans (oil) well sites (Figure 1). Subsequently, in 2013, we acquired infill 19
Scatterplot of % Oil against MPOG Oil + Gas; categorized
100
80
Gas Gas & Oil Oil
% Oil
60
Hans shows higher gas anomalies in surfaces samples than Fritz, despite the latter beeing a gas discovery
40
20
0 0
20
40
60
80
100
120
140
160
180
200
MPOG Oil + Gas Figure 2: Anomaly characterisation scatter plot displays normalized MPOG OIL + Gas versus Oil anomalies. Observe the difference clusters. Highlighted is data from the prospect (red-yellow-green) and condensate/gas discovery wells Ref I-III within (blue box). Note that prospect values (in green shading) show a significant number of oil prone samples and show higher values of oil & gas.
samples to better define selected anomalies and also coverage of geologically analogous discoveries in a nearby concession for interpretative constraint. The most reliable indicators for thermogenic hydrocarbons were the the microbial data (“Microbial Prospecting for Oil and Gas� MPOG, Wagner et al., 2002), calibrated by well control data. It indicated geospatially coherent multipoint anomalies that fit the geology: discoveries, fault (subcrops), layer subcrops and Fluid Inclusion Screening (FIS, http://fittulsa.com/) data as wells. Sampling in a grid enabled us to map ends of migration pathways, as well as background data. Microbial Prospecting for Oil and Gas (MPOG), after Wagner et al. (2002) measures the activity of hydrocarbon-oxidizing bacteria in surface soil or sediment samples. Higher bacterial activity is thought to reflect a greater supply of gaseous hydrocarbons coming from deeper-seated oil or gas reservoirs, and thus a higher microbial popu20 | MED OIL & GAS | July 2018
lation. This differentiates between hydrocarbon-prospective areas and areas without hydrocarbon indications (background level). MPOG calims to be able to differentiate between an oil and gas signal, by separately identifying methane and C2-C6 hydrocarbon-oxidizing bacteria. We identified gas-prone and oil-prone microbial anomalies with reference to a corporate MPOG database of some 1,000 records from the Norwegian shelf and imaged these using the red-green color scheme exemplified in figure 1 & 2.
Workflow/Findings First we investigated the spatial distribution of the signal; here the structural frame work (seismic) is important. In our study we quickly established a clear relationship between basement faults and signal distribution at the surface. Furthermore, we identified a subset of high signals that were associated with a dipping carrier bed sub-
crop, indicating lateral transport of the signal (figure 3). The utilization of scatter plots (Figure 2) plotting gas vs oil calibrated against reference wells was helpful. This proved to be a powerful tool to identify the relative strength of the signal/anomaly and to be able to predict HC phase as we had both gas and condensate analogue wells in our study (Ref I-III, Hans and Fritz in Figure 2). Both gas and oil anomalies are present but there is also an overall condensate signature, as evidenced by Hans and Fritz gas wells. The data from directly above the prospect are clearly more oil prone than all of the sampled reference wells (Figure 2). Additionally, the anomalies associated with the subcrop show similar composition as anomalies overlying the prospect. Samples with the clearest oil signature were found over the prospect. The above findings enable us to distinguish between a direct signal, transported verti-
cally by small fractures in the overburden and a component/fraction that was subjected to lateral transport due to dipping beds in the overburden. Proof of this is seen in a prominent anomaly coinciding with the subcrop of the “dipping beds”. The base Tertiary amplitude anomaly indicates the top end of the migration pathway, which explains the relative oil prone anomalies aligned with the base Tertiary subcrop (Figure 2 & 3). This lateral transport can also explain the false positive oil signature in the Hans and Fritz wells. Tying FIS data from wells to seismic also gave valuable insights. As shown in Figure 3, FIS anomalies are clearly confined to certain intervals (“carrier beds”). Elevated values are found in layers that are more sandprone. These intervals are inclined, allowing for lateral transport. Samples with higher values occur on top of major basement features and fault offsets (green circles & arrows in Figure 3).
Quantifying the relative amount of lateral and vertical seepage is impossible at this stage of the study, but would be a very interesting topic to investigate further. A potential next step could be to model processes in the subsurface to gain a better understanding of the dynamics of material transport, utilizing flow simulators for example.
Evidence from other studies Similar observations that confirm lateral transport in the overburden are made by Chand et al., (2012) in the Barents Sea and by a study by BP Thrasher et al., (1996) on the Haltenbanken. They conclude that leakage does not necessary occur directly above accumulations, and shallow gas and oil occur at the seabed where the Paleocene crops out along the Norwegian margin. Oil seepage is displaced by up to 50 km between accumulations and source kitchens. In the Barents Sea, Vadakkepuliyambatta et al., (2013) established that !argest fluid-flow
features occur above major deep-seated faults in the area suggesting a close relationship between the two.
Conclusions MPOG analysis of shallow coring indicates contribution both from lateral and vertical migration, however the respective amount is difficu!t to assess. This is confinned by offset wells with FIS data and study of geosections (interpreted seismic). They indicate a component oflateral migration causing Hans and Fritz-like oil anomalies, despite being classified as dry wells (NPD). While data from reference discoveries are gas prone, prospect samples are clearly more oil prone. This information was used to decrease the source risk, which as a consequence was set to proven.
Major learnings Careful study of seismic data that fits the sampling pattem is very important in understanding the role of faults, trace sig-
Figure 3: N-S seismic line across prospect . The Hans well is displayed with FIS data, yellow colour indicates sandier, carrier interval. Note that FIS anomalies are associated with these intervals. Wavy arrows represent proposed flow/migration path, purple line and arrow indicates the subcrop line. Data courtesy of TGS 21
nal pathways, identify “carrier beds’’, and to map subcrop morphology. Pattems in sampling proved to be very advantageous. The importance of good well calibration is evident, ideally with different HC content/phase. Information of fluid inclusions proved to be helpful too (FIS Data in this case). Anomalies plotted in scatter diagrams proved to be a very useful visualization tool. It is often claimed that seepage occurs only vertically. We hope to have outlined that instead lateral migration can in principle result with the same signatures as vertical migration above the prospect. The key is that rather than utilizing this data as a direct HC indicator to de-risk the prospect, they are used to de-risk the petroleum system as a whole.
Authors: Klaus Dittmers DEA Deutsche Erdoel AG R. Hatton CVC Ud Acknowledgements TGS and FIT are thanked for the permission to use their data. Morten Bergan, former RWE DEA Norge colleague is thanked for introducing the first author in this topic and is the ‘godfather’ of surface sampling in the company. ENGIE and (former Marathon) Aker BP are thanked for their cooperation in PL582 and for their pennission to publish this paper. References Chand, S., Thorsnes, T., Rise, L., Brunstad, H., Stoddart, D., Bøe, R” Lågstad, P. and Svolsbru, T., 2012. Multiple episodes of fluid flow in the SW Barents Sea (Loppa High) evidenced by gas flares, pockmarks and gas hydrate accumulation. Earth Planet. Sci. Lett. 331-332, 305-314. Thrasher, J” Fleet, A. J., Hay, S. J., Hovland, M. and Dtippenbecker, S. 1996, Understanding geology as the key to using seepage in exploration:
spectrum of seepage styles, in D. Schumacher and M. A. Abrams, eds., Hydrocarbon migration and its near-surface expression: AAPG Memoir 66, p. 223-241. Vadakkepuliyambatta, S” Btinz, S” Mienert, J. and Chand, S. (2013). Distribution of subsurface fluidflow systems in the SW Barents Sea. Marine and Petroleum Geology; Volum 43. ISSN 0264-8 172.s 208 - 22 1.s doi: 10. 1016/j.marpetgeo.20 13.02.007. Wagner, M., Wagner, M., Piske, J . and Smit, R. 2002: Case histories of microbial prospection for oil and gas, onshore and offshore in northwest Europe. In: Schumacher, D & L. and LeSchack, L.A. (eds.): Applications of geochemistry, magnetics, and remote sensing, AAPG Studies in Geology 48 and SEG Geophysical References Series 11, p. 453-479 .
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Offshore potential and opportunities in the Netherlands Introduction A considerable volume of oil and gas reserves and resources still to be discovered is expected to be present offshore the Netherlands. Hydrocarbon exploration and production in a cost-efficient, safe and sustainable manner will continue to fuel the current energy transition. The Southern North Sea, of which the Dutch offshore forms a part, is considered a mature area regarding exploration. However, in EBN’s opinion there are still many attractive opportunities left which view is
Fig. 1 The Netherlands with leads in the Dutch Northern offshore identified by EBN.
28 | MED OIL & GAS | July 2018
supported by two recent significant discoveries and play-openers. FID for fast track development of a significant discovery (4 bcm GIIP) has already been taken. A second play-opener has been established in the hitherto well-known Rotliegend system and an appraisal well is just being drilled to further investigate the delineation of possibly a series of fields. Other areas, such as in the Northern offshore, remain relatively under-explored. EBN (the Dutch National O&G Company) is actively working on those areas to identify and share new opportunities (fig 1).
Petroleum Geology of the Netherlands The Netherlands is a gas dominated country with several proven play-types present. Thick Permian Zechstein salt present in a large part of the subsurface provides an effective seal between the Paleozoic gas system and the mixed oil and gas bearing Mesozoic hydrocarbon system. The most attractive reservoir in the Netherlands is formed by Early Permian, Rotliegend sandstones but other proven reservoirs ranging in age from Carboniferous to Quaternary are present as well. Several new opportunities
Fig. 2 Petroleum plays in the Netherlands.
have been identified beyond the well-established fairways, some of which are indicated on fig 2.
Data Within the Dutch Mining Act it is arranged that in general subsurface data is treated confidential for a period of five years after acquisition after which it is released to the public (with some exceptions). Relevant data is managed by the Dutch Geological Survey, and they offer released data to the public for free, and in an efficient manner through the NLOG portal (www.nlog.nl). This includes data from ca 6500 deep onand offshore wells, and an almost full coverage of the Netherlands with 3D seismic data.
Opportunities: Shallow gas â&#x20AC;&#x201C; bright opportunities in the Dutch offshore 3D Seismic data in the northern Dutch offshore shows many shallow amplitude anomalies in Cenozoic sediments at shallow depth (< 1km), often indicating the presence of gas. The Netherlands was the first country in the North Sea region in which these types of accumulations have been successfully developed. Miocene-Pleistocene unconsolidated sands form here reservoirs, sealed by
intercalating clays. Traps are generally low relief 4-way dipping anticlines formed by underlying salt domes. Currently there are 8 discovered shallow gas fields of which 4 are now successfully producing. Production rates of 3 million Nm3/day have been achieved here, making this one of the best producing fields in the Netherlands. And there is still significant additional potential, since many more shallow structures, leads and prospects are identified (fig 3).
Shallow gas lead: F12-Pliocene In EBNâ&#x20AC;&#x2122;s resource portfolio the F12-Pliocene lead ranks high. This structure is a four-way dip closure with a reservoir thickness of ~50 m and a net-to-gross of around 85%, based on several offset wells. The porosity is expected to be more than 25% and gas saturations around 60%. This lead is fully covered by 3D seismic data and the outline of the amplitude anomaly observed on seismic conforms to the mapped structure. A flat spot, seismic push-down effects and attenuation can be observed below the top sand reflector (fig 4), all indicative for the presence of gas. Considering the presence of several other shallow leads in its close proximity and the opportunity to explore for other, deeper targets, this lead is
considered very attractive requiring further maturation.
Opportunities: Triassic Prospectivity in the Dutch Northern offshore The Triassic Main Buntsandstein play is well established in the Dutch on- and offshore area. Mixed aeolian and /fluvial deposits classified as Lower Volpriehausen and Detfurth Sandstones constitute the main reservoir rock. It is generally perceived that Triassic reservoir presence and efficiency decrease towards the North and consequently, few wells have tested Triassic reservoir in the Dutch Northern offshore. However, a regional review currently being carried out suggests the presence of reservoir sands extending further north beyond the established main fairway. Fluvial sands with an alternative provenance from the North may have been preserved locally which is supported by seismic interpretation indicating the development of local depocenters during the Early Triassic. 53 leads have been identified here, with an (unrisked) cumulative in-place volume of 100-125 bcm. Three types of Triassic leads have been identified in the Dutch northern offshore. 29
1. Classic leads with proven trap, source, seal and reservoir types 2. Leads where structures may be sourced with HC’s via Tertiary volcanic dykes 3. Leads with alternative reservoir provenance in the northwestern Step Graben. Currently EBN is working on further de-risking of several of the identified leads.
Opportunities: Lower Carboniferous – a virtually untested play The Carboniferous Visean and Namurian deposits in the northern Dutch offshore have significant hydrocarbon potential. EBN’s analysis indicates the presence of traps, source and reservoir rocks in the study area. Abundance and thickness of good res-
ervoir-quality sands increase from the UK towards the North East in the study area (fig 5). The lower Carboniferous Scremerston coals are the most promising source rocks in the northern part of the study area. In the southern part charge may occur from organic rich lower Carboniferous basinal shales and laterally from Upper Carboniferous Westphalian coals. There are numerous fault and dip closures at the Base Permian unconformity, below Silverpit shales and Zechstein salt, which are proven regional seals. These combined fault/dip closures are dependent on juxtaposition sealing across faults. The presence of intra Lower Carboniferous seal(s) provides significant volumetric upside. • 20 structures have been identified on the Base Permian Unconformity (BPU)
Fig. 3. Study area showing the eight shallow fields (red), of which four are currently producing, and the additional identified shallow leads
30 | MED OIL & GAS | July 2018
depth map, all 4-way dip closures. Provisional P50 GIIP’s add up to ~75 BCM (unrisked). • The Lower Carboniferous clastics play is established in the on- and offshore UK part of the southern North Sea, with fields producing from Namurian and Visean reservoirs. • It is concluded that the play is virtually untested in the Dutch northern offshore.
EBN EBN is the Dutch National Energy Company and invites you as an investor to explore in the Netherlands. EBN participates as a normal industry partner in exploration, production and transportation of oil and natural
Fig 4. F12-Pliocene Shallow gas lead. A time map of the main reservoir showing amplitudes and a seismic line through the lead. The top of the reservoir is indicated by the yellow dotted line.
Fig 5. Play elements of the Lower Carboniferous plays
gas, onshore the Netherlands and on the Dutch continental shelf of the North Sea. Its shares are held by the Dutch State. The company is a non-operator with in general an interest of 40% in the joint ventures with operators. Due to our participation in almost all licenses in the Netherlands, EBN has a wealth of data, knowledge and experience pertaining the subsurface. The exploration team builds upon this data to carry out regional studies, with the goal to investigate plays and add value through lead and pros-
pect maturation. The main focus is to support operators to de-risk exploration opportunities and activities. EBN has a team of experienced exploration geoscientists, dedicated to support both established operators and new entrants to find and de-risk opportunities. Financial risks and exposure for the investors are lowered through EBN’s 40% participation, also in the exploration phase of projects. In addition, the Netherlands has a favorable fiscal
regime which, in combination with EBN’s participation, limits the financial exposure of an operator to a maximum of 20% of the cost of an exploration well. Our offshore wells are relatively cheap due to the shallow water depth operated in, which ranges from 100 – 150 feet. Study results and recommendations are made available to the public through presentations at conferences, posters, publications, workshops with interested parties and 31
data-portals on the EBN website (www.ebn. nl). Some examples of these portals are the Geo-Drilling Events database, based on review of 1000+ wells and growing, and the Hydrocarbon Shows database, based on review of 700+ wells and growing.
Application for an exploration license in the Netherlands The extraction of oil and gas in the Netherlands is regulated through the rules of the Mining Act (Mbw), the mining Decree (Mbb) and the Mining regulations (Mbr). An extraction project is divided into four phases in the Mining Act, namely: 1. 2. 3. 4.
Surveying (seismic survey) Prospecting (exploration) Extracting (production) Cleaning up (abandonment)
Phase 2, prospecting, concerns the application for an exploration license prior to any drilling. An exploration license is granted by the Minister of Economic Af-
fairs. The application for an exploration license must contain an indication of both an area and a time period. Furthermore, documentation regarding the applying company, a geological report and a work program and budget needs to be included in the application. After receipt, the Minister publishes a notification of the application in the Bulletin of Acts and Decrees and in the Official Journal of the European Union to invite other parties to submit competitive applications. A decision is taken within six months of the end of this submission period. The decision period can be extended once by six months.
In summary Many attractive opportunities for economic quantities of oil and gas still remain to be found (offshore) in the Netherlands. Most subsurface data older than 5 years is digitally available and can be downloaded free of charge. Studies and analyses of the subsurface data are also available for free. For
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more information you may contact us at exploration@ebn.nl.
Author Annemiek Asschert  Deputy Exploration Manager at EBN, the Dutch State participant in oil and gas in the Netherlands. Annemiek graduated in 2007 from Utrecht University and received a MSc in Earth Sciences.
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Malta - seeks accredited investors for oil exploration In April an international Euromed Oil and Gas conference was hosted at the Grand Hotel Excelsior. This was the first time that Malta was chosen as a venue for an impressive three-day summit on the subject. One of its aims is to help global industry players make the right strategic connections. Speakers discussed the geo-strategic, commercial, technological and regulatory issues that confront the hydrocarbon industry in the European Med region by giving advice to delegates on how to make best use of technological advances in exploration techniques such as sub-sea and remote well intervention. All this is linked to how to maximise return on investment on transportation, storage and extraction. More than thirty international speakers discussed the latest developments in the Adriatic, Balkans, Eastern Med, North Africa and the Middle East. Other interesting topics include talent sourcing and managing health and safety issues. In attendance were a number of producing countries including Turkey, Croatia, Greece, Italy, Albania, Israel, Sweden, USA, Eygpt, Cyprus, Norway and North Africa. In this context, it is encouraging to note that PKF presented a paper at the Euromed Oil and Gas Summit discussing the potential for the island to become a future servicing hub. Was the timing of the event a harbinger that oil prices are escalating and may soon reach
$100 per barrel? Commentators at the conference warned that any loss of supply from Iran due to US sanctions will exacerbate the pressure on oil prices and one cannot expect OPEC to intervene and increase output in the interim.
The steep losses from Venezuela combined with the potential disruption in Iran could force the oil price to reach unexpected heights any time soon. Back to the topics discussed at the Malta conference, it is opportune to discuss our history of explo35
ration. Nostalgically, looking back more than sixty years ago one recalls how the government embarked on a drive to offer parts of Malta’s offshore acreage among oil companies to prospect for oil and gas. Precisely it was 1954 when the first onshore concession was awarded to a company called D’Arcy Exploration (BP) to drill a well in Naxxar. All attempts since then failed with some dry wells, others with some oil and gas prospects but no commercial success followed albeit it is positive news that the main source rock for the oil is expected to be rich in the organic Streppenosa oil shale unit which is designated world class in its prolific oil generating capabilities. No wonder the offshore Sicily Vega oil field, with an estimated resource of one billion barrels of oil in place, is only 20km away from the northern border of the latest zone in Malta’s exploration efforts. Needless to say, experts predict that the proximity of similar concessions and similarity in geology to the producing basins of Tunisia and Sicily lend support to the theory that oil strikes for Malta cannot be excluded. The “intra-basin” ridge trend offers a new and highly prospective oil strike in our waters. Mediterranean Oil and Gas (MOG) a company which in 2005 was awarded a licence to explore for oil and gas had commissioned a specialist operator to shoot a seismic survey and it succeeded to interpret an extensive long-offset 3D view over the area which looked promising (yet no official announcement has so far been issued). It is undisputed that this part of the offshore site which is geologically analogous to the Libyan Sirte Basin, appears to contain analogues to proven producing fields in Libya in addition to those offshore Tunisia. It is interesting that experts have identified a portfolio of prospects in the Lower Eocene/Paleocene sequence. The powerful scientific survey has for the first time allowed imaging of the Cretaceous and Jurassic sequences, enabling several large leads to be defined at this stratigraphic level. Concurrently it is pertinent to quote Peter Gatt, a qualified ge-
36 | MED OIL & GAS | July 2018
ologist who had conducted his own study consisting of a detailed geological analysis of the Malta platform. His study focused on the analysis of rock samples from six exploratory wells drilled in the Maltese platform by corporations including British Petroleum, Total and Shell, with some information dating back to 1956. A recent announcement states that an application for permits to link Malta’s gas network grid to Gela in Sicily is well timed. This gas pipe will eventually link us with the rest of Europe. The environmental studies will begin this year, followed later on by a public call for tenders next year. Last year a National Oil Company has been incorporated to help promote upstream business so can we hope that behind closed doors the authorities are devising plans to kick start the drive for exploration. As an island we still rely 100% on fossil fuel for electricity generation albeit now using LNG given that our dependence on renewable energy is under 7% and it does not look as if it is going to triple in the short term - so the global oil price is an important factor for us as an importing country. Late last year, it was thanks to a scoop by the Times of Malta (TOM) which revealed that the government appears to be trying to start a new push for oil and gas exploration in the Maltese continental shelf after a hiatus of six years. TOM quoted that the official journal of the European Union issued a notice says that Blocks 1, 2 and 3 of Area 3, an area of 6,000sq.m north of Malta, are now available “for authorisation on a permanent basis under either an exploration licence or an exploration and production licence”. Some may say this is a pipe dream yet realists assert that provided sufficient capital is invested in exploration using modern technology, if we strike gas in sufficient quantity, in a decade we could start to export to Europe via a submarine pipe connected to Sicily. A successful discovery would trail blaze a bright future for a new servicing industry.
Author George M Mangion George Mangion is a senior partner at PKF Malta, an audit and consultancy firm, and has over thirty years’ experience in accounting, taxation, financial and consultancy services. His efforts have seen PKF Malta be instrumental in establishing many companies in Malta and placed PKF Malta in the forefront as professional financial service providers on the Island. George is a regular contributor to both local and foreign publications on business, oil exploration, financial services, taxation, and company structure. George Mangion was in Aberdeen, Scotland where he held a number of meetings over seven days with tax experts, international lawyers and professionals from the Port Authority, the Oil & Gas UK organisation, a number of support operators, the North Sea industry and the Bank of Scotland. He also attended a breakfast briefing delivered by top officials from oil majors entitled “Maximising Economic Recovery from UK Continental Shelf”, at Boyd Orr Hall, Aberdeen Exhibition and Conference Centre. He has also lectured and delivered presentations at numerous seminars and conferences worldwide, namely in Europe, South Africa, North and South America, Canada, Australia, China and the Caribbean.
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38 | MED OIL & GAS | July 2018
International Exploration in the Next Cycle: “Back to the Future” Exploration seems to have become a dirty word in E&P investment circles since the beginning of the oil price crash in mid-2014 and the subsequent 3+ years of ‘downturn’ during which time little or no new investment has been made in looking for new reserves (fracing in North America aside). But is exploration really a dirty business? The answer should really be NO seeing as it has been responsible for finding most of the hydrocarbons the world remains completely dependent on for its energy. There is no doubt a case that the use of hydrocarbons is ‘dirty’ but even then, far less so than coal and it’s still more acceptable than nuclear and definitely more effective and efficient than most renewables at this point. No other source of energy can be transferred so effectively in such small volume with the same energy contained in it compared to hydrocarbons. All the politicians seem to think they can accelerate the use of alternatives tomorrow, and replace hydrocarbons by electricity, but is it really possible seeing as it took nearly 40 years from the first production combustion engine cars in the 1920’s until coal fires steam trains were replaced by diesel engines in the 1960’s. In any event, what is going to fuel these power stations assuming all the new power plants needed can be built, which based on history need at least 20+ years lead time! Perhaps this explains the Major’s strategy of increasing their gas portfolios?
The point here is that assuming the transition to alternatives, with a reduction in combustion engine use is now in process, we still need lots of hydrocarbons for this 30 – 40 years transition to occur, where nowhere near enough new exploration has gone on for nearly 4 years during the downturn to guarantee the near term supply! The down turn has also dramatically reduced the upstream industry’s ability to re-juvenate exploration it in the time that is probably needed nearer term too. The main issues facing the Exploration Sector’s return to finding oil and gas can be summarised: 1. True Understanding of Exploration Risk: Over 18 years, the data from over 3,000 farmout deals tracked by independent JSI Services shows that of the total number of exploration farmout deals available over that time (not including North America) only around 5% have resulted in a potential commercial discovery. Not all of these projects resulted in drilling, however, where of those that did resulted in wells, around 15% resulted in discoveries being declared. This means that 85% of the projects actually drilled were unsuccessful. This is a fact that many non-technical people simply have never appreciated. YES exploration is Risky…..but then so is laying bets on a horse race but peo-
ple still bet. They just bet appropriate to their means and have an understanding of risk, which as this article will later suggest, has not been the case in the E&P business and in particular the financing of! 2. The People Capable of finding it: Many established exploration teams, mostly made up of Geologists and Geophysicists (G&G) have been broken up during the down turn and resulted in many of the experienced oil and gas finders either retiring and many will simply not be willing to work 9-5 any more when things pick-up. This is on the back of the long 1984-2003 crash which saw few Geologists and Geophysicists joining the business, resulting in a ‘generation gap’ of experienced people between the ages of 55 and 35. This is only now hitting exploration companies’ ability to hire enough G&G people, let alone those with hard learnt experience and capable of generating ‘smarter’ exploration opportunities with less risk to the investor! Why are G&G people so important in exploration?, because not many engineers, lawyers, accountants, bankers and financiers have been that good at deciding, let alone knowing where to drill a 6” hole in thousands of square kms when you can’t see below the surface with the naked eye and find the hydrocarbons. 39
Global Deal Discoveries: 2000 – 2016
3. The ‘Right’ Money to Finance new & sustained Exploration: Back in the early 1980’s, and questionably the early 1990’s, far more small E&P companies had modest cash flows from a few barrels production which they used to fund their G&G teams to generate new plays and prospects which they then farmed out to bigger companies. These then ‘cherry picked’ the best deals to supplement their own in house generate prospects, able to take and fund the exploration risk whilst ‘carrying’ the prospect generator for a modest percentage of the project. Equally interesting is the number of big company successes that have come from small company prospect generation over the years. The statistics also show that a farmout is not more risky than one done privately as farmouts over the last few decades have the same success rate as in-house generated projects, which are not farmed out. Such exploration deal promotion, supported by small productive cash flow, thus enables the smaller prospect generators to maintain their search for ‘quantum leap’ rather than what happened after 2003 when the long 20 year oil crash unlocked and markets seemed happy to give listed oil companies millions to go and drill one or two wells 100% believing they were exploiting 40 | MED OIL & GAS | July 2018
guaranteed reserves. The markets were keen to get on the band wagon, but seemingly totally unaware that 85% of exploration wells were doomed to fail commercially as the stats clearly define. On this basis, if one wants an odds on chance of success one surely needs to plan to participate in at least 5 or 6 wells, and questionably 10+. If people do not believe this, just go back to the long historical list of small E&P companies on the Global markets that are gone after running out of money having funded several unsuccessful exploration wells. The problem is perhaps linked to the fact that successive upturns see a completely new flood of young market makers, who do not have the experience of the previous cycles, let alone a true understanding of exploration risk, but the city demands for profits tomorrow, do not recognise the need for an exploration investment strategy, risked and valued over 5+ years.
Keys to Exploration Success If one looks at companies that have achieved value over 5 years, however, there are some highly successful groups that do it time and time again. In each case, they understand exploration risk, employ the best ‘teams’ of technical and exploration guru’s which work out the best strategy and together
sort and reduce the risk rather than by the direction of one autocratic decision maker. The successful exploration companies also participate in multiple well programmes to beat the odds of 85% failure and management manages this effectively rather than chopping off the technical plan after the first few failures. They also then properly reward those technical idea generators for their 15% success and its value, which more often than not pails into insignificance the cost of the 85% failure. They also critically, either have enough initial finance to allow the success to happen, until they generate their own production cash flows, or they acquire small ‘overhead covering’ cash flow to allow an appropriate percentage participation in exploration over time and progress through and beyond the inevitable failures. Irrespective of what is successful over the longer term, what will ensure that exploration will be less of a dirty word to investors in the near future? Perhaps another new influx of the finance sector management will forget the past (after most of the last crew were cleaned out since 2016) get the bug after seeing recent oil price rises, and again perceive an opportunity for short term profits from companies offering big value from successful exploration! Lets hope that the history is reviewed and more appropriate finance planning is adhered to.
Influence of US Resource Plays on Future Oil Price So what about past, current and future oil price? This last oil price crash, which saw oil prices above US$100 / bbl crash to less than US$ 30 over 14 months from mid-2014 to early 2016 was party the knee jerk to the ‘Resource’ or so called ‘Fracing’ Boom in North America. Although significant, in its ability to unlock large quantities of oil from low poro-perm rock, there are an increasing number of articles questioning its profitability and ability to generate large guaranteed returns to shareholders. To do date, it does not seem to have done this in the US even though the price of oil has increased dramatically since it was declared, by some, as the next big oil revolution. Yes, the middlemen trading acreage, the banks financing the huge sums needed to drill and frac increasingly long multi-lateral wells, and service companies providing the fracing kit and crews have done well these last few years, but now there are problems with the supply of enough sand and water, which might upset the ability of even the US to reduce the economy of scale sufficiently to generate longer-term profits. The value of fracing to contribute to Global oil is less in doubt than the bigger question as to whether the resource plays can replace the natural decline in conventional production. This is still responsible for 90% of the World’s oil, but on which significant pressure is now building caused by the lack of investment over the last few years. This is needed
to maintain the 5-9% decline of 90% of the Worlds production? Of the US$ 750 billion quoted by various sources needed to work over the worlds existing conventional fields, and maintain their production less than US$ 350 billion has been spent over the last few years which is only likely to increase their rate of decline. New fields coming on-stream since the crash have certainly helped maintain supply, but many of these were authorised and pre-financed before the crash. Several big E&P companies have also sold their international conventional portfolios and have retrenched into the US to focus on resource plays even though this has resulted in those companies producing much less oil that they were before their retrenchment.
Future Need for Conventional Oil Whilst fracings ability to fill this future conventional production shortfall is questionable and the politicians wish to switch to renewables to replace the need for lots more conventional oil in the next few years, is admirable. In reality, the evidence suggests this is not likely even in the medium term. Oil is here to stay as the primary source of our energy for several decades so unless we restart the search for new sources of easy to produce ‘conventional’ oil and gas, there is probably more likely to be an undersupply of oil in the medium to long term and an increase in the price rather than a crash, (which the markets seem so keen to predict,) but having not predicted the current
oil price or the crash in 2014, who knows? Few experts seem to have ever consistently predicted oil prices and certainly most missed the crash and upturn, where today, at the time of writing this article, the price of Brent has come very close to U$80/bbl and been consistently above US$70 bbl for nearly 3 months. In fact, amusingly, if one had simply predicted what would happen based on the opposite of what most experts had predicted you’d have been more right! If this is right, the price may go the other way and continue to grow way above where the experts have not predicted, which is more likely to happen based on their historical success. We are perhaps also fortunate that the Middle East is keen to keep the price around US$ 70 bbl to fund their social programmes in the near term, which will hopefully enable enough confidence to facilitate new exploration for the medium to longer term.
A&D Market Status What will affect whether these issues in reality become critical is also worth considering. The amount of E&P activity can be measured by seismic crew and rig activity but this is generally in response to activity 12 months before. The A&D (Acquisition and Divestment) activity is a better indicator and historically has always tracked oil price. See attached graph of Global Farmouts completed against the oil price. They match very closely albeit that in early 2014 before the price crash, the number of deals being
Global Deal Flow Historical Events Vs Global Upstream Farmout Deal Flow (Excluding North America) 2000 - 2017
41
done was already reducing, probably due to the spiralling costs inhibiting the ability of investors to risk the funding as the sector overheated. The increasing oil prices recently have certainly generated a lot more interest in exploration opportunities and unlike the height of the market back in 2014, costs are now a fraction of what they were, and so exploration is cheap compared to the potential returns from higher oil price. Now is questionably the best time to be consummating deals. Successful exploration in the near term will hopefully coincide with development when prices are even higher. Although interest in exploration has clearly picked up, we have not seen the flood of deal-making to back this up yet, but if oil prices are maintained and/or continue to grow and break the US$ 80 price threshold, 2019 could see a mini-Tsunami of exploration deal-making with the back log of opportunities and new money available. Deals involving production are already starting to lead the way and a potential indicator / pre-curser to the renewed exploration deal making.
Who will be doing the Exploration deals? New players are being created all the time but still have limited resources and certainly can’t complete with the bigger established companies although many will be responsible for generating many of the new exploration plays over the next few years as exploration activities return. The issue is that many of the experienced G&G teams have been let go by these established companies and are themselves now responsible for setting up the new small companies. This transfer of knowledge and G&G ‘oil finding’ expertise now lost to the bigger companies sets up the potential for the farmout of new projects back to the established companies, which are less equipped to create the adventurous new ideas needed to unlock new and existing play potential. Perhaps no different from the 1980’s when a similar transfer happened. The only difference then was that there were no generation gaps in the experienced staff G&G demographics.
Back to the Future Questionably the criteria of ensuring that this new influx of Exploration companies is successful is not just their technical ability to generate opportunity but to do so in a manner that offers them a half even’s change of success. The management of risk
is therefore more important than finding enough good technical projects.
more not less exploration failure and yet another ‘bust’.
The factors that will effect ability to deliver successful exploration can therefore be summarised
Let’s hope we can learn from these past mistakes and more exploration is managed, risked and financed to be sustained overtime, going ‘back to the future’ rather than sending the ‘future to the back’ in this perhaps last big hydrocarbon E&P cycle needed by the World to allow time to properly deliver the cleaner and more efficient alternative energies of the future.
• Availability of enough experienced G&G staff to reduce risk through smarter exploration, and knowing how to effectively use all the new technology. Bridging the gap between the experienced G&G people who joined the industry before 1985 and then survived the long industry downturn until 2003 when a new influx of very capable but now less experienced G&G people joined the E&P sector is a major issue. • Oil Price……which may go above where the experts have predicted and put added pressure on the need for new exploration and worst, encourage the investor community to pour too much money in the wrong companies caught up in the hype and poorly risked project portfolio’s. • Markets and Private Equity financing therefore needs to look back at the history and fund the future in the old way, properly risked rather than funding a new boom that will inevitably lead to
Author Mike Lakin Managing Director Envoi Limited www.envoi.co.uk
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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 actually 1178. Tragically, though, 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. 47
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 has 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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48 | MED OIL & GAS | July 2018
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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 BSc MNI, 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 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 visit www.mmass.co.uk
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50 | MED OIL & GAS | July 2018
INVERSION OF GROUND CONDUCTIVITY METER DATA FOR MAPPING OF RAW MATERIALS ABSTRACT Access to raw materials is important for our society and the extraction of it can be very expensive. It depends on several factors such accessibility, volume and depth of the raw material. To get the knowledge of the extent of the material, traditionally boreholes have been drilled in a grid, which is very expensive. A quicker and less expensive method is to map the area with a geophysical instrument such as a ground conductivity meter. By processing and inversion of the data, the results given as maps and profiles are highly detailed and can reduce the number of boreholes. By correlating the inversion models with boreholes, the geology of the area can easily be interpreted and reduce both time and costs of the extension of e.g. a gravel pit.
Using geophysics and Aarhus Workbench in raw material mapping Mapping raw materials is normally done by drilling a grid of boreholes to gain detailed knowledge of the materials depth and extend. This method is often expensive and time consuming, especially if the area consists of complex geology. Within the last years there has been a significant development of geophysical equipment with a big lateral and spatial resolution that can map at high speed. Using this equipment along with the integrated GIS interface, processing, inversion and QC tools of Aarhus Workbench, gives new possibilities to effectively use geophysics methods to get a full surface coverage when mapping
raw materials. The results will give a better understanding of the geology which is not possible to gain with information from boreholes alone. By using the inversion models from Aarhus Workbench along with borehole information to translate the geophysical data into raw material geology, mapping of raw materials can be done quicker and cheaper with better results than what you can correlate from just boreholes. This paper presents results from a gravel pit at KalbygĂĽrd in Denmark which is a project made by Aarhus University and Central Denmark Region. The purpose of this project is to map the thickness of the moraine clay above the glacial gravel and sand from geophysical data
Fig. 1. The DUALEM-421 system on two sledges towed behind an ATV.
This paper will show a case from a gravel pit where mapping with and inversion of geophysical data done in few hours gives much highly detailed results of the thickness of the moraine clay overlaying the glacial sand/gravel deposits. These results can be used to see where it is cost-effective to extract the raw materials and where to place the boreholes to analyze the quality of the raw materials.
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Fig. 2. Map of the gravel pit at Kalbygård. The blue lines are mapped with the DUALEM-421 instrument and the red dots are boreholes.
and finally make a detailed geological interpretation by comparing with borehole data for validation.
The instrument The ground conductivity meter DUALEM-421 is an electromagnetic instrument which uses induction to get information from the subsurface. The instrument is a 4-meter-long tube that contains a transmitter coil in front and receiver coils at the end at a distance of 1, 2 and 4 m from the transmitter, which gives a penetration depth around 5-10 m, depending on geology. The transmitter generates an electromagnetic field (primary field), which induces current fields in the subsurface. The current in the subsurface then generates a new electromagnetic field (secondary field), which is measured in the receiver coils. This secondary field can be translated to resistivity or conductivity and will be dependent of the water content, soil type, etc. E.g. clay will have a high conductivity and sand/gravel will have a low conductivity. 52 | MED OIL & GAS | July 2018
The instrument is protected in a white tube placed on the sledges and towed behind an ATV, giving a mapping speed up to 20 km/h with a sampling frequency of 10 Hz, which gives a high lateral resolution. A differential GPS is logged along with the data with a sampling rate of 5 Hz and data points are interpolated between the GPS points.
Aarhus Workbench software Aarhus Workbench is a unique and comprehensive software package for processing, inversion, and visualization of geophysical and geological data. The package integrates all steps in the workflow from handling the raw data to the final visualization and interpretation of the inversion models. The Aarhus Workbench package includes dedicated data processing modules for many geophysical data types, in an integrated GIS platform. It uses the robust and fast inversion code AarhusInv.
GCM module The GCM (Ground Conductivity Meter) module includes import, processing, and inversion of GCM data. Any coil configuration
can be imported and inverted. System information is easily added during data import. Processing, quality control, and inspection of inversion results are integrated with the GIS interface providing the user with a complete overview of the workflow from raw data to final results. Modelling and presentation to the customer is carried out with the well-known functions of the Aarhus Workbench so that integrating with boreholes, creating reports etc. is easily done and only a few clicks away.
Key features • Flexible and easy to use importer, which supports any kind of GCM system setup • Fully developed processing tools and automatic data filtering • Integrated with the GIS interface • Automatic LCI/SCI data inversion • Visualization of data, inverted models on the GIS interface and on cross sections • Integrated QC tool
VALUE Starting model
Number of layers Starting resistivity [Ωm] Layer thickness first layer [m] Depth to last layer [m] Layer thickness distribution
12 100 0.1 10 Logarithmic increasing with depth. Fixed.
SCI constraints
Horizontal constraint - resistivities [factor] Reference distance [m] GCM height above ground Vertical constraint - resistivities [factor] Number of SCI cells
1.3 1 28,5 cm 2.0 1
Table 1. Inversions-properties, smooth SCI setup.
Fig. 3. Mean resistivity map in the depth interval 3-4 m.
Kalbygård data mapping The gravel pit at Kalbygård is 30 hectares and consists of moraine clay overlaying glacial sand and gravel. The thickness of the layers is very different within short distances. The moraine clay varies from 10 m in some areas to non- existing in other areas. A 50-hectare area around the gravel pit has been mapped with the DUALEM-421 instrument and 15 boreholes up to 10 m deep have been drilled (figure 2). With the DUALEM-421, 50.200 data points have been recorded with a line spacing of 10-20 m and 30 cm between data points along the lines.
The survey time was 3½ hours and the following processing, inversion and interpretation took 3 hours.
Data processing and inversion Negative data and noisy data due to couplings from buried cables have been removed in the processing. Data within 5-10 m near known buried cables have been removed. Most negative data are seen at the end of lines where the ATV turns and gets too close to the instrument. To get a better signal to noise ratio, the data has been averaged with a median filter with a distance of 1 meter. An absolute uncer-
tainty of 1 ppm and a relative uncertainty of 5% has been added to data. Data has been inverted with a 12-layer 1D SCI inversion (Spatially Constrained Inversion). An SCI inversion is a 1D inversion with 3D constraints. There are constraints on resistivity along lines, between lines and between layers. Inversion settings are listed in table 1. The Depth Of Investigation (DOI) is also calculated for each inversion model. The DOI gives an estimate to which depth the models can be trusted for interpretation.
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Results The results are represented as mean resistivity maps, profiles and thickness of the moraine clay. Model information below the DOI has been removed from the profiles and maps. Colors from blue to yellow (values below 110 Ωm) represents moraine clay and colors from orange to purple (values above 110 Ωm) represents sand/gravel. Gravel will have a higher resistivity than sand (purple color). Figure 3 is the mean resistivity maps in the depth interval of 2-3 m (top picture) and 3-4 m (bottom picture). The mean resistivity maps indicate how different the geology in the area is and how fast it changes with depth.
Fig. 4. a) Profile 1 with boreholes. b) Profile 2 with boreholes. The black line shows the boundary between the moraine clay and sand/gravel.
Figure 4a and 4b is resistivity profile 1 and profile 2 located in figure 5. Each profile includes boreholes and has a black line, which marks the boundary of 110 Ωm that defines the thickness of the moraine clay. The map with the thickness of the moraine clay in figure 5 is created from this boundary. There is a good correlation between the geophysical models and the borehole information. Also, the thickness of the moraine clay varies several meters within the survey area and a lot of these places will not be seen with borehole information alone. On profile 2 purple structures with very high resistivity is seen. Unfortunately, there is no borehole information in these areas but it is expected to be coarse gravel deposits. In figure 5 the depth to the 110 Ωm boundary has been mapped with information from all 50.200 inversion models. This boundary is also displayed in the squares representing the boreholes and the correlation of the boundary between boreholes and inversion models are good for all boreholes except one.
Conclusion Using geophysical data to map raw materials is efficient, covers a big area in few hours and results in maps and profiles with high detailed information. Combining these results with borehole information to describe the geology, the thickness of the overburden can easily be determined. This information can be used to locate new areas that is profitable to use as gravel pits. By using the geophysical data in the beginning of a new excavation also gives a cost-effective mapping by pinpointing where to put the boreholes, reduce the
54 | MED OIL & GAS | July 2018
Fig. 5. Map with thickness of the moraine clay and location of profile 1 and 2. Squares are borehole locations.
number of boreholes and increase the detail level of the results. Last, the area that can be covered with this geophysical method is much bigger than with boreholes alone. A total of 6 hours is used to do field work and processing and inversion of data, which makes this a quick method to screen the geology in the subsurface. This article is focused on mapping of raw materials, but processing and inversion of ground conductivity meter data can be used for many other purposes like: vulnerability mapping, mapping of soils, archaeological structures, human installations and geotechnical engineering projects.
Author Toke Søltoft CEO Toke is a geophysicist from Aarhus University who has worked at CSIRO, Perth and the HydroGeophysical Group of Aarhus University before starting Aarhus GeoSoftware in 2015 as a CEO. Thanks to Jesper Bjergsted Pedersen from the HydroGeophysics Group, Aarhus University
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Portable filter unit for on-board hydraulics Compact, mobile and versatile Stauff has developed a compact portable filter unit for mobile filtration of decentralised on-board hydraulic systems. It can easily be transported to the place of use, even in confined spaces. Versions for 50 Hz power supply on land and for the 60 Hz on-board electric system can be supplied. Hatches and gates, stabilisers, winches, steering gears and loading systems â&#x20AC;&#x201C; passenger and transport vessels are equipped with a variety of decentralised hydraulic systems. The use of mobile filter units can be necessary in these systems for maintenance work or to temporarily support the integrated filters. Stauff has developed the filter units type SMFS-P-015 specifically for this application. They feature very compact dimensions and are portable rather than on wheels, as transport across several levels or through hatches and space saving storage are crucial criteria on ships. The high-quality gear pumps in the units have good suction behaviour to pump fluid media through the Stauff filter element with a viscosity between 10 and 400 centistokes. The pumps are driven by energy efficient three-phase motors (class IE2). A pressure switch prevents damage to the components, e.g. when lines become blocked. To provide best possible protection of the pump against the negative effects of coarse contamination, a washable stainless steel mesh filter is used in the suction line. 56 | MED OIL & GAS | July 2018
The portable filter devices are available with two different motor/pump units: The 50 Hz version is suitable for power supply on land, while the 60 Hz drives can be supplied by the on-board electric system. In both cases, the combination of compact dimensions and high performance provides the basis for universal and highly flexible use on board, especially as the units can be equipped with all common spin-on cartridges from the Stauff range with Micron ratings from 3 to 125 micrometres. The visual contamination indicators on the filters allow the filter elements to be replaced as required. The units can be used to efficiently clean hydraulic systems as well as lubricating systems on mineral oil basis. They are not only suitable for preventive maintenance and servicing of the ship hydraulics â&#x20AC;&#x201C; during maintenance work, for temporary support of the integrated filters or as bypass filters on large-volume systems. Equipped with a suitable blank filter element, they are also used for draining and transferring container contents.
Fig 1. The mobile filter unit SMFS-P-015 was developed especially for use on ships. Its features include the portable design and the selection between 50 Hz and 60 Hz drives.
A suitable filtration device is also useful for filling hydraulic systems with fresh oil. This is because fresh oil can usually not be designated as pure, as it is rarely fine-filtered during production and processing and particles can additionally be introduced during filling, transferring and transport (e.g. in reconditioned barrels). This provides service personnel on ships and maintenance service providers with a highly flexible system for on-board purification of hydraulic and lubricating oil systems. The robust design of the filter units ensures a long service life even under high strain. www.stauff.com
Fig 2. The compact unit can be used for maintenance work and also for draining or refilling systems.
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Kent Introl Undertake Major Shutdown On Leading UK Refinery Kent Introl recently completed a major shutdown project of approximately 140 valves for a leading UK refinery. Having successfully undertaken 3 previous shutdowns for this client, Kent Introl was the first port of call and went on to fulfil requirements within a four week turnaround period.
58 | MED OIL & GAS | July 2018
First steps The scale of this project set it apart from previous shutdowns as it totalled approximately 140 valves at completion. From the off, it was clear that Kent Introl had the capacity to undertake the project in a cost effective and timely manner, owed to our in-house facilities and highly experienced team. Our project managers would also be proactive throughout, ensuring that each stage of the shutdown ran smoothly in order to deliver the best possible results: “Communication and client collaboration are vital for a project of this scale,” explained Martin Broadbent, Global Product Manager - Aftermarket. “It’s important to maintain a clear, constant dialogue throughout and ensure the client is actively involved and satisfied at each stage.” This included meetings with the engineers responsible for each refinery unit, where we analysed the specifications and conditions of every valve and made our recommendations. It was clear that some valve internals could be overhauled rather than new replacements supplied, which dramatically reduced costs.
Planning The next step was a full team planning meeting with Kent Introl’s service engineers and Service Manager, Nick Parker. Our intention was to identify any points that could save time and enhance our service. The exercise was a perfect demonstration of the Kent Introl attention to detail. For instance, it was deduced that a larger wagon with fewer collection and delivery journeys would be more cost effective for the client. This ultimately saved more than 50% per valve in transportation.
It was also decided that a full service of each piece of test equipment and overhaul machinery should be completed before launching the shutdown, which safeguarded against failure and ensured the highest quality results that Kent Introl are known for.
The process Once the foundations were laid for an efficient project we began to assign numbers to each valve and ordered the necessary parts. The valves, which ranged from 1” to 16” control valves, were then delivered in batches and booked in upon arrival. After identifying the correct numbers on the paperwork we took photographs for reference of flow direction and the instrument setup. Pre-ordered spares kits for every valve were then allocated with the valve to the engineer. Several valves required immediate testing and were sent straight for leakage tests. The valves could now be stripped down and assessed, with bodies, bonnets and actuators taken back to base material using our high performing shot-blasting machine. After any necessary machining the valves were then returned to the engineer for rebuild, before sending them to our testing bay for hydro testing and seat leakage tests. After successful testing, the valves could be painted. The final stage involved moving the valves into the dispatch area and pulling together the documentation. Each valve then underwent a torque check and instrument check by engineers, followed by a final review and sign off by a manager. “One thing we never compromise on is procedures,” said Martin. “Everything we do is in line with the Kent Introl procedures which are audited every year.”
Highest quality guaranteed Over the years Kent Introl have built a reputation of efficiency, expertise and the highest standards, all of which were exhibited throughout this shutdown. Our industry-leading facility and equipment also contributed to the success of this project, ensuring a fast turnaround and the highest quality finish. Our people also play a leading role in the Kent Introl service. For this shutdown we assembled a highly skilled select team that consisted of Kent Introl service, application and design engineers, each with exceptional knowledge of our company, our processes and our products. This team proved incredibly balanced and dedicated, working together seamlessly throughout the project. Reflecting on the success of this major refinery shutdown, Martin said: “This project is proof that the more you plan, the better the results. We put together a team of people who made it a pleasure to come to work each day. Everything ran smoothly and the results show this.”
The end result The shutdown was completed well within timescales and the client was extremely satisfied with the results. Plans are in place for a follow up meeting to discuss the shutdown and to highlight recommendations for future shutdowns. Kent Introl are also in discussions with other clients for similar projects.
KOSO Kent Introl Tel: +44 1484 710 311 Email: info@kentintrol.com www.kentintrol.com 59
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not execute our current and future projects in the North Sea”, says Alexander Eijgenraam, Rigmanager of Seafox 5. “Depending on the future market we also might look into more possibilities for our crane”, he continues.
Rotterdam (Netherlands), – Lieherr-MCCtec Rostock GmbH, Liebherr Maritime Benelux B.V. together with Damen and Seafox BV have modified one of Liebherr’s biggest offshore cranes in the field. The assembly of the BOS 45000 took place in December last year. With a maximum lifting capacity of 1,200 tonnes the BOS 45000 is the biggest crane of the board offshore crane series. The structure of the slewing bearing crane is based on an A-frame design to achieve optimal stability and reliability. The lattice boom construction enables higher outreaches. One of these large sized rope luffing type cranes is operating on board of the Seafox 5. The self-propelled DP2 jack-up vessel, owned by Seafox BV has been modified recently. The modification contains a boom extension of almost 20 metres, thus the crane has an optimised outreach of 96 metres in excess. 800 tonnes can be handled at the maximum outreach. With this change the crane is able to install higher wind turbines. “The market for wind turbines made the decision to enlarge the boom. It became necessary because of the height of the towers from wind turbines which is continuously increasing. Without this extension we could
Back in 2012 when the crane has been assembled the first time in Singapore the 18 metres long intermediate boom section was also part of the contract. However, due to the order situation of Seafox at that time, the crane was delivered with a shortened boom. The current modification was not only a reaction on the changing market where wind turbines are getting taller. It also underlines the vessel owner’s strategy to be flexible in the offshore business and qualifies the 151 metres long and 50 metres wide vessel for a recent customer inquiry. The contract, which started in February 2018 and is now halfway completed, includes the installation of 66 six-megawatt wind turbines at Merkur, a wind farm in the German North Sea. With the modified boom length the vessel is ready to install the next generation of larger wind turbines with mast heights of up to 78 metres. However the idea behind this additional intermediate section was to adapt the boom length rapidly and efficiently with a minimum effort. This allows Seafox to either shorten or extend the boom depending on specific project requirements. The adjustment for the upcoming project has been solved by providing a temporary solution.
A benchmark for maritime services The planning of this project took a lot of time. Liebherr and Seafox held dialogues for
nine months before the realisation started. Both companies jointly developed a cost effective solution. The centrepiece of the approach is a hoisting gear that was especially invented to meet the project related needs of the customer. After dismantling the intermediate and head section in November 2017 the boom length had been adapted at DAMEN Verolme Rotterdam shipyard. As part of the work preparation for installing the extended boom the pivot piece was hoisted via bolt flanges. To estimate the maximum forces a study had been launched by Liebherr. According to the results of this study static analysis and simulations were made. Afterwards a basic concept of the hoisting gear was developed. Because of the need to be precise, the interaction between the mounting team, including Liebherr service engineers and the used support floating crane was very well executed. “Fitting in the lengthening of the boom next to the maintenance area of the pivot section of the boom, the exchange of all outside hoses, the weather conditions and the coordination of all parties working on the crane were major challenges during this project. But due to the outstanding effort of Liebherr, EuroRope, de Gier, Damen Verolme, FluiConnecto as well as Seafox and their cooperation, this project has become a success,” summarizes Mr Evert Kistemaker, Seafox project engineer and coordinator. “The execution of the service and the support made by Liebherr has been very satisfactory and valuable,” he adds. After 12 hours, the assembly of the boom had been done and the crane was ready for its upcoming tasks. 61
ROTECH SUBSEA OPENS ASIA OFFICE IN FACE OF DEMAND FOR ITS UNRIVALLED CONTROLLED FLOW EXCAVATION CAPABILITIES
Photo caption (L-R): recent Asia team meeting with Stephen Sin, Edmond Kumar, Jamie Ross (Subsea Manager) and Stephen Cochrane (Director of Subsea).
Rotech Subsea’s recent successful free-span correction project in the Yangon field, has led to such a stream of enquiries that they have established a local company, Rotech Subsea Asia Sdn Bhd, and opened an office in Kuala Lumpur, Malaysia, to meet demand. Basing a brand new spread of their ground breaking RS excavator range there, and taking on several local employees, demonstrates Rotech’s commitment to, and expectations of, the Asian market. The project, in which Rotech was contracted by Pathfinder with MOGE as the end client, 62 | MED OIL & GAS | July 2018
saw a TRS2 spread deployed from the UK to the Yangon field, Myanmar, for a 2-3 week free-span correction project on a live 24 inch pipeline, the largest export pipeline into Yangon. With accuracy critical due to the free-span’s range from just 0.1m up to 0.7m, the client chose to import Rotech’s TRS2 tool due to its unrivalled power and controlled flow. Rotech Subsea Asia will be headed up by new Business Development Manager, Edmond Kumar, who joins respected excavation specialist and Asia Team Leader, Ste-
phen Sin in the KL office. Supported by its parent company Rotech Subsea Ltd, the new entity brings decades of cable trenching and pipeline burial/deburial experience to the region. The local presence now means that Rotech’s RS range of excavators, which boast higher performance capabilities than other tools on the market, are now available for quick mobilisation for IRM works in the region as far afield as China, Indonesia, Australia and India.
Speaking about the Asian expansion, Director of Subsea, Stephen Cochrane, said: “On the back of the Myanmar project for MOGE, our Asia team has been inundated with enquiries - including at the recent OTC and AOG trade shows. “The MOGE project was significant because the client chose to import the Rotech team and our TRS2 CFE spread despite there being other competing equipment available in country. It is a prime example of Rotech Subsea establishing itself as the partner of
choice in the region not just for IRM scopes - where Rotech has earned a reputation as having the most effective remedial tools on the market - but for entire scopes of work where the Rotech Subsea team manages the survey, vessel & tool operations in-house, bringing greater efficiencies to clients. “Now word is spreading that we have a base in the region with an experienced team and our new range of RS spreads, we have been taken aback by the interest and look forward to growing our presence in Asia.
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Equinor offered interesting licences in 24th licensing round The Ministry of Petroleum and Energy has offered Equinor 7 licences in the 24th licensing round – 5 operatorships and 2 partner positions. “We have a clear ambition of maintaining profitable production at today’s level on the Norwegian continental shelf (NCS) until 2030 and beyond. It is therefore crucial that we are awarded new exploration acreage beyond already opened areas. We are pleased with the offer we have received today,” says Arne Sigve Nylund, Equinor’s executive vice president for Development and Production Norway. The award includes a commitment well in the southwestern part of the Barents Sea. Equinor has also been offered an interesting licence in deep waters in a frontier part of the Vøring Basin in the Norwegian Sea. “This award is in line with Equinor’s exploration strategy, securing us access at scale.
Exploration on the Norwegian continental shelf (NCS) is becoming ever more challenging. It is important to Norway and the companies to map remaining commercial resources both in the Norwegian Sea and the Barents Sea. We see the need for testing new exploration models and that is what we aim for in these licences. Proving alternative exploration models is the best way of fully mapping the NCS resources,” says Nicholas Ashton, head of exploration on the NCS. “We have built on our 40-year history in North Norway and our long exploration experience from the Barents Sea. We therefore want to clarify the potential in the western margin of the Barents Sea and in the Hoop area around Wisting. A Equinor team has
The West Hercules drilling rig in the Barents Sea. Photo: Ole Jørgen Bratland
worked for a long time on preparing this application, and I am very proud of everyone who has coopered across Equinor to secure the award we received today,” says Ashton.
AWARDING DRILLING AND WELL SERVICE CONTRACTS WORTH NOK 30 BILLION
In contrast to the awards of the 23rd licensing round, the majority of these awards are less mature and therefore require more work before the drilling candidates are ready. Consequently, Equinor will gather and interpret data before the licences are presented to the partners who will decide on any drilling of exploration wells. “Our drilling campaign in 2017, and the cooperation we have seen in the industry through Barents Sea Exploration Collaboration (BaSEC) prove that we can drill safely and in a commercially competitive way in these areas,» indicates Ashton. “This as a great opportunity for us. We firmly believe that if we find a sufficient amount of resources we will be able to develop them in a profitable and sustainable manner,” concludes Nicholas Ashton. In the 24th licensing round Equinor has been offered new production licences in the following areas: • 100 % share and operator for production licence PL957 (blocks 6201/6 og 6202/4) • 50 % share and operator for production licence PL959 (blocks 6503/8, 11, 12 og 6504/10, 11) • 40 % share and operator for production licence PL960 (blocks 7018/4, 5) • 50 % share and operator for production licence PL961 (blocks 7116/6 og 7117/4, 5) • 70 % share and operator for production licence PL966 (blocks 7325/2, 3, 6, 8, 9 og 7326/4, 7, 8, 9 og 7327/7, 8 og 7426/10, 11) • 30 % share and partner for production licence PL963 (blocks 7422/10, 11) AkerBP is the operator • 35 % share and partner for production licence PL537B (block 7324/4) - OMV is the operator
Equinor is awarding new service contracts to Baker Hughes Norge, Halliburton AS and Schlumberger Norge AS for integrated drilling and well services on most of the Equinor-operated fields on the Norwegian continental shelf. Initially awarded for four years, the contracts have a total estimated value of some NOK 30 billion. The contracts include options for five 2-year extensions. Extension of the contracts is subject to continuous achievement of the goals for well deliveries. “This is a great day for Equinor and the Norwegian continental shelf. The contracts are the biggest we have ever awarded within drilling and well service. The integrated delivery model we have chosen will strengthen the interaction between the service supplier, rig supplier and operator, enabling us to drill more wells. This, in turn, will enhance recovery and ensure long-term operations,” says Pål Eitrheim, Equinor’s chief procurement officer. The purpose of integrated drilling and well services is to clarify roles and responsibilities. This results in less interfaces and more clearly defined responsibilities, facilitating more seamless planning and implementation of the operations between the various contributors.
www.equinor.com
The Grane platform in the North Sea. Photo: Harald Pettersen / Equinor ASA
65
HYDROGEN COMPRESSION FOR MULTIPLE NEEDS
THE NEA 360° PORTFOLIO TO BOOST HYDROCRACKERS Hydrocrackers comprise the heart of the refinery. Inside the giant reactors, heavy waxy feedstock is converted into lighter products such as jet fuel, kerosene and diesel fuel. Today’s crackers need large quantities of hydrogen to convert high-sulfur material into low-sulfur fuels for vehicles and airplanes under high temperatures of up to 800°C/1,500°F. As hydrocrackers require major invests, reliable equipment such as reciprocating compressor packages are mandatory. The NEA heavy-duty hydrogen compressor is named as the best-in-class solution for hydrocrackers due to its tailor-made design and flexibility in driving high volume flows of up to 100,000 Nm³/h at some hundred bar discharge pressure and up to 30 MW power. As reliability counts, no single installation is left unattended. From start-up to maintenance and professional diagnostics, the service provider NEAC Compressor Service keeps the compressor running. Worldwide, with full life-time support. Authorized OEM supplier for reciprocating compressor lines:
GROUP
HOFER manufactures diaphragm and hydraulically driven piston compressors, and offers high-pressure piping systems with threaded connections. Perfectly tight even under vibrations from hydrocrackers. STASSKOL supplies sealing elements such as intermediate packings as well as guide and piston rings based on in-house materials for lubricated and non-lube hydrogen piston compressors. PEEK materials are ideally suited for high gas pressures and thus high mechanical loads during the hydrocracking process. NEA X connects engineering and digital technology. Its solution provides Condition Management with OEM expertise, transferring intelligent service and diagnostics to tangible values: optimized assets availability, more time to plan right actions, and improving profitability.
NEUMAN & ESSER GROUP www.neuman-esser.com
Tracerco Receive Lloyd’s Register (LR) Recognition TM for Discovery – The World’s Only Field Proven Subsea CT Scanner any type of unpiggable, piggable, coated and uncoated subsea pipeline. The technologies help oil and gas operators make informed decisions regarding the extension of asset life, ensure the integrity of their assets, understand flow assurance issues and have confidence in planning critical pigging operations.
Tracerco, part of Johnson Matthey plc, has been awarded LR recognition for its acclaimed subsea CT scanner: DiscoveryTM. The Qualification Trials of Discovery™ were conducted in a simulated subsea environment at Tracerco’s HQ in Billingham, UK and successfully determined the depth limit for reliable POD (Probability of Detection) and typical sizing tolerances for metal loss anomalies at the inner and outer positions of subsea pipes. These capabilities were determined in accordance with recognised guidelines for offshore pipelines and were further validated using Non-destructive Examination standards specifically for the technique of Computed Tomography (CT). Ben Metcalfe, Subsea Technical Manager at Tracerco commented on the recognition by stating: “We are extremely pleased to have this qualification programme recognised by LR who provided valuable technical input in terms of the specific NDT technique and the general qualification process. The results give our customers an assurance that the qualification was conducted in compliance 68 | MED OIL & GAS | July 2018
with international standards and guidelines for offshore pipelines.” In addition to its Flooded Member Inspection (FMI) service, Discovery™ is Tracerco’s second technology solution to receive the industry respected recognition from LR, demonstrating the innovative and high quality standard of its market leading subsea portfolio. With over 1000 scans completed since its launch, Discovery™ has been at the forefront of subsea pipeline inspection, obtaining accurate measurements of pipe wall thickness through any type of protective coating whilst simultaneously diagnosing and characterising flow abnormalities within subsea pipelines without interruption to normal pipeline operations. In 2017 alone, Discovery™ enabled operators to save millions by running cost effective inspection campaigns in the Gulf of Mexico and the Arabian Gulf. Tracerco offers a range of field proven subsea technologies that also deliver real-time condition monitoring of subsea assets. Its technologies are used in the non-intrusive inspection of platforms, pipelines, buoyancy tanks and other subsea vessels, including
About Johnson Matthey Johnson Matthey Plc is a global leader in sustainable technologies. It applies cutting edge science and creates solutions with customers to make a real difference to the world around us. Its proud of its products and technologies, how its customers use them and the positive impact they have on our planet. At the same time, Johnson Matthey are passionate about how science can enable global solutions for clean air, improved health and make the most efficient use of our planet’s natural resources. Johnson Matthey’s 200-year commitment to innovation keeps them at the forefront of technological breakthroughs that make the world a better place. Enabled by their science, manufacturers across many industries, including automotive, petrochemicals and pharmaceuticals, apply its innovations to improve the function, performance and safety of their products at a lower environmental cost. Johnson Matthey has operations in over 30 countries and employs around 13,000 people. Its products are sold around the world to a wide range of advanced technology industries. For more information on Johnson Matthey visit its website at www.matthey.com
www.aramco.com
NEWS RELEASE
Corvus Energy to provide energy storage for shore stations to charge Fjord1 electric ferries Corvus Energy’s market-leading Orca Energy ESS has been selected by NES for the shore stations at Brekstad and Valset to power new Fjord1 low-emissions hybrid-electric ferries Corvus Energy will supply nearly 5 MWh of combined stored energy capacity usingOrca Energy battery systems for Fjord1 shore stations and ferries operating on the Brekstad-Valset and Husavik-Sandvikvåg routes.
Richmond, British Columbia, Canada Corvus Energy is pleased to announce that it has been selected by Norwegian Electric Systems (NES) to supply the Energy Storage Systems (ESS) for the shore stations at Brekstad and Valset, Norway. This follows the contract awarded to Corvus Energy in late 2017 to supply the ESSs onboard the two new low-emissions hybrid-electric ferries that will operate on the Brekstad-Valset route, as well as one ferry on the Husavik-Sandvikvåg route—all designed by Multi Maritime and operated by Fjord1. Each shore station will have a capacity of 565 KWh, charged from the grid with clean, renewable hydro-electric power. The 1137 KWh Corvus Orca Energy ESS systems onboard the Brekstad-Valset ferries are a key component of the NES hybrid-electric propulsion system. Although the ferries will be equipped as hybrid ferries with batteries and diesel engines, the diesel engines will have limited use in docking, or in case of a power outage on the power grid, or during rescue-operations. Normal operation will be 70 | MED OIL & GAS | July 2018
all-electric, powered by the Corvus batteries. “A project of this magnitude requires reliable, safe and cost-effective power and energy storage systems”, says Stein Ruben Larsen, Vice President Sales at NES, a total system integrator of diesel electric and hybrid electric systems for the global marine market. “With the Orca ESS from Corvus, we achieve all of those objectives.”
equipping its fleet with the industry’s most advanced and environmentally-friendly technology to reduce emissions, as well as operational costs. At 66.4 meters long and 14.2 meters wide, each Brekstad-Valset ferry will have a capacity of 50 cars, 6 trucks and 195 passengers. Construction is underway at Havyard Ship Technology with delivery scheduled towards the end of 2018.
Ferries are an integral part of the transportation infrastructure along the west coast of Norway, crossing the fjords and connecting the islands to the mainland. Norway Road Authorities’ strict emissions limits in maritime environments create technical opportunities and challenges for system integrators such as Norwegian Electric Systems. Energy storage systems are at the heart of many of their projects. NES’ Larsen comments, “The technical and commercial support from Corvus’ local Bergen office was instrumental in securing this contract.”
“Corvus Energy is very honoured to have been selected to supply the battery systems for the Fjord1 electric ferries and shore stations,” says Roger Rosvold, Director of Sales & Key Account at Corvus Energy. “The Orca Energy ESS continues to set the standard for maritime energy storage solutions due to its innovative approach to performance, safety and affordability.”
Fjord1 continues to demonstrate its commitment to environmental sustainability by
As the leading manufacturer of energy storage systems for maritime applications, Corvus offers the innovative Orca ESS solutions portfolio and has unsurpassed experience from 140+ projects, totaling over 100MWh and 1.5 million operating hours.
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Zuverlässigkeit From Butterbrot to Energiewende, many German words are known round the world. We’ve added one more to the list: Zuverlässigkeit, meaning reliability. That’s what we, Germany’s biggest oil and gas producer, stand for in Europe, North Africa, South America, Russia and the Middle East. www.wintershall.com