Adrin Shafil

Petrofac Drilling and Completions Manager
Last Updated: August 16, 2017
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Drilling & Completions
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During my first month as a young drilling engineer, I was sent for a hitch on a drilling rig at offshore Terengganu. My head was giddy with the vision of the awe I would receive upon stepping on to the semi, and impress people with my genius. After all, I had in my backpack my university TI82 graphing calculator, a thick company issued laptop, Excel pre-installed and I had made a point to read at least 1/3 of the Drilling for Dummies book during the weekend before. I entered the chopper cabin with hopes and dreams, and was sure that this was the start of an illustrious career.


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Unfortunately, my earlier personal euphoria was gutted swiftly when I exited the chopper in a dazed stupor, trying to get my bearings on which was port and starboard, and wondering why nobody can just say left or right. Pointed to the briefing room direction by the HLO, I still managed to successfully go down the wrong set of stairs, while struggling to keep upright on non existent sea legs fighting against the rig sway. After finally being pushed impatiently by a fellow traveler to the right doorway, I sat gratefully in the front row through the safety induction, looking for the nearest waste paper basket in case my digested lunch decides to come up the wrong way. After the last presentation slide, I shook hands with the rig OIM and jolly old rotund medic, who then proceeded excitedly to show me locations of the galley, lifeboats and room. The images of the food being prepared in the galley, and the sight of tightly made top bunk in the four person occupied room, filled my mind with hopes for dinner and a deep slumber. Unfortunately those images were replaced with dread, when I was informed that actually my work shift had started. And like everyone else, especially as a newcomer, I would start my shift with the honour of meeting the drilling supervisor, aka the king of the rig, aka the company man.


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Gingerly swaying in my shiny boots, I walked through the corridors and found the company man's office, eerily situated at the dimly lit end with the door half open. I knocked, and only silence greeted me. I knocked again, and a sudden bravado overcame my senses and I stepped in, because it occurred to me that technically, I was a company man too. Shifting to the middle of the room, my presence continued to go unnoticed by the man in charge. He was just sitting there on a rickety chair, gazing out to the rig floor through the smudged safety glasses and half opaque window. He looked very uncomfortable, hunched in filthy coveralls withered by what I assume to be continuous rig laundry and exposure to mud and sun, but he maintain his slouched posture in deep thought. I tried to calm my nerves and grunted a half swallowed "Hello, I'm Adrin, boss", and waited for him to respond. For another full 5 mins he continued his silent meditation, his deadlocked eyes just continued to stare into space. Then, his cracked lips moved ever so slightly, lisping the words no driller ever wants to hear, "We just stuck pipe". Unfortunately for me, I didn't know how dire a situation that actually was, and with the cheeriest voice I could muster, I said, "Oh good, then I can learn about what stuck pipe is!". He looked up and peered at me through his safety glasses, and gave me the most disgusted grunt. "You are here to learn, right? Then by all means, learn. Get your PPE, I'll show you what a stuck pipe is. I want you to figure out how to get free, and until you let me know how you are able to do that, or we free the pipe, you will spend your shifts on the rig floor. You will only come down for meals and safety meetings. Is that clear, whoever you say you are?".

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Side note: Just for the benefit of non-drillers, during drilling operations, a pipe often with expensive bottom hole assembly (tools, or referred to as BHA) is considered stuck if it cannot be freed from the hole without damaging the pipe, and without exceeding the drilling rig’s maximum allowed hook load.


        So there I was, first week offshore, already incurring the wrath of the company man, and already bought a front row seat on a stuck pipe event. The experience itself, is as interesting as the namesake, a pipe stuck, stationery and unmoving. Most days were spent with me spewing obvious solutions like "pull harder...let's try twisting it...let's pull now because maybe whatever has the pipe in its jaws has tired of holding on to it.." As time passed to days, and into the second week, I saw the mighty top drive pull and jar up and down on the pipe in futility, and over time people started to talk to it, hug it, curse at it, but most of the time stare at it. Somebody actually suggested that we slaughter a black chicken and drip the chicken's blood on to the stick up, but when I took the idea seriously and suggested it to town, I could still recall the cruel laughter on the other line and comments about how the contracting to buy the animal alone would take too long. What i learned though was, once a pipe is stuck, it generally stays stuck. The only recovery was to continue to work on the pipe until we received approval to cut the pipe as deep as we can, and pump cement across the tools downhole and leave it buried. As we had nuclear sources in the tools, it was only until the government gave the approval on the 10th day, could the attempts to free the pipe cease, and I saw wireline tools run to cut the pipe, and the recalcitrant pipe finally was freed without the tools downhole, and cement plugs pumped above the abandoned BHA, tools worth millions of dollars left for the next generation to unearth.


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Pictured: A picture I found online on how other crews help start the well process with prayers or Pooja. I hope that the flowers and belief did help this particular rig stay trouble free. 


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If there is anything that the oil fields ingrain into a man, it's humility. We can try to predict what will occur, be ready with an assortment of fallback plans and equipment, and try to avoid certain conditions that might lead to catastrophe. Unfortunately in drilling, we deal with the unknown. The mystery of the unknown is more prominent in exploration or appraisal drilling, but even in development mode, the formation drilled can throw us a curve ball. Every single meter drilled have different characteristics, but challenges for every single meter cannot be addressed with real time changes, at least not with the technology available now. Apart from managed pressure drilling technology, all wells are drilled with normalised planned parameters, tools, fluids and practices, and the mode is always progressing while avoiding catastrophe. But when stuck pipe occurs, while we can likely deduce that its most likely caused by a deviation, a practice that went wrong, we cannot expel the notion that there is the element of the unknown that the sentences the pipe to its final grave.


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For non-drillers, I often explain a stuck pipe as an earthquake catching our tools. Indeed the simplified metaphor covers the likely causes of stuck pipe. Formation movement, debris, collapse, ruptures, key seats, pressure differentials are what the common man associates earthquakes with, albeit on a much larger scale. Unfortunately, more often than not, a stuck pipe is notched to a mistake made by the drilling crew. But drilling crews are also human. Training, drills, procedures, data analytics and supervision are all available for the driller and crew to make decisions, but just like our normalised parameters, they are often unable to predict and react easily for every single meter drilled. Thus a stuck pipe event will still remain a real catastrophic event, that until our technology catches up with real time response of equipment with real time inflow of data, we will have to put our faith on the team with the right attitude and knowledge to keep us out of trouble.


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However, a stuck pipe event still remains a commercial event. While it does introduce its safety risks with possible flow inside the pipe due to trapped pressure, there are many other drilling incidents that are far worse, often involving immediate injuries, explosive events and death. While any stuck pipe event often brings me back to the memories of my youth, standing across an unmoving stub, full of despair, I would take a hundred stuck pipe events before I would go through the ordeal of having casualties under my watch. Our focus on performance and continued diligence in trouble shooting should never falter, and make we have less stuck pipes in our careers, but more importantly we all stay safe and return to our homes unhurt.

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Your Weekly Update: 12 - 16 August 2019

Market Watch 

Headline crude prices for the week beginning 12 August 2019 – Brent: US$58/b; WTI: US$54/b

  • Saudi Arabia’s overtures to further stabilise prices was met with a largely positive response by the market, allowing crude prices to claw back some ground after being hammered by demand concerns
  • Saudi officials reportedly called other members in the OPEC and OPEC+ producer clubs to discuss options on how to stem the recent rout in prices, with an anonymous official quoted as saying that it ‘would not tolerate continued price weakness’
  • Reports suggest that Saudi Arabia plans to keep its oil exports at below 7 mmb/d in September according to sales allocations, which was seen as a stabilising factor in crude price trends
  • This came after crude prices fell as the US-China trade war entered a new front, causing weakness in the Chinese Yuan, although President Trump has floated the idea of delaying the new round of tariffs beyond the current implementation timeline of September 1
  • Crude had also fallen in response to a slide in American crude oil stockpiles and a receding level of tensions in the Persian Gulf
  • In a new report, the International Energy Agency said that the outlook for global oil demand is ‘fragile’ on signs of an economic slowdown; there is also concern that China will target US crude if the US moves ahead with its tariff plan
  • The US active rig count lost another 8 rigs – 6 oil and 2 gas – the sixth consecutive weekly loss that brought the total number of active rigs to 934
  • Demand fears will continue to haunt the market, which will not be offset so easily of Saudi-led efforts to limit production; as a result, crude prices will trade rangebound with a negative slant in the US$56-58/b range for Brent and US$52-54/b for WTI


Headlines of the week

Upstream

  • Nearly all Anadarko shareholders have approved the Occidental Petroleum deal, completing the controversial takeover bid despite investor Carl Icahn’s attempts to derail the purchase
  • Crude oil inventories in Western Canada have fallen by 2.75 million barrels m-o-m to its lowest level since November 2017, as the production limits in Alberta appear to be doing their job in limiting a supply glut while output curbs are slowly being loosened on the arrival of more rail and pipeline capacity
  • Mid-sized Colorado players PDC Energy and SRC Energy – both active in the Denver-Julesburg Basin – are reportedly in discussion to merge their operations
  • Pemex has been granted approval by the National Hydrocarbon Commission to invest US$10 billion over 25 years to develop onshore and offshore exploration opportunities in Mexico
  • Qatar Investment Authority has acquired a ‘significant stake’ in major Permian player Oryx Midstream Services from Stonepeak Infrastructure Partners for some US$550 million, as foreign investment in the basin increases
  • PDVSA and CNPC’s Venezuelan joint venture Sinovensa has announced plans to expand blending capacity – lightening up extra-heavy Orinoco crude to medium-grade Merey – from a current 110,000 b/d to 165,000 b/d
  • BHP has approved an additional US$283 million in funding for the Ruby oil and gas project in Trinidad and Tobago, with first production expected in 2021
  • CNPC, ONGC Videsh and Petronas have reportedly walked away from their onshore acreage in Sudan, blaming unpaid oil dues on production from onshore Blocks 2A and 4 that have already reached more than US$500 million

Midstream/Downstream

  • Expected completion of Nigeria’s huge planned 650 kb/d Dangote refinery has been delayed to the end of 2020, with issues importing steel and equipment cited
  • Saudi Aramco’s US refining arm Motiva announced plans to shut several key units at its 607 kb/d Port Arthur facility in Texas for a 2-month planned maintenance, affecting its 325 kb/d CDU and the naphtha processing plant
  • ADNOC has purchased a 10% stake in global terminal operator VTTI, expanding its terminalling capacity in Asia, Africa and Europe
  • A little-known Chinese contractor Wison Engineering Services has reportedly agreed to refurbish Venezuela’s main refineries in a barter deal for oil produced, in a bid for Venezuela to evade the current US sanctions on its crude exports
  • Swiss downstream player Varo Energy will increase its stake in the 229 kb/d Bayernoil complex in Germany to 55% after purchasing BP’s 10% stake
  • India has raised the projected cost estimate of its giant planned refinery in Maharashtra – a joint venture between Indian state oil firms with Saudi Aramco and ADNOC – to US$60 billion, after farmer protests forced a relocation

Natural Gas/LNG

  • The government of Australia’s New South Wales has given its backing to South Korea’s Epik and its plan to build a new LNG import terminal in Newcastle
  • Kosmos Energy is proposing to build two new LNG facilities to tap into deepwater gas resources offshore Mauritania and Senegal under development
  • In the middle of the Pacific, the French territory of New Caledonia has started work on its Centrale Pays Project, a floating LNG terminal with an accompanying 200-megawatt power plant, with Nouvelle-Caledonia Energie seeking a 15-year LNG sales contract for roughly 200,000 tons per year
August, 16 2019
The State of the Industry: Q2 2019

The momentum for crude prices abated in the second quarter of 2019, providing less cushion for the financial results of the world’s oil companies. But while still profitable, the less-than-ideal crude prices led to mixed results across the boards – exposing gaps and pressure points for individual firms masked by stronger prices in Q119.

In a preview of general performance in the industry, Total – traditionally the first of the supermajors to release its earnings – announced results that fell short of expectations. Net profits for the French firm fell to US$2.89 billion from US$3.55 billion, below analyst predictions. This was despite a 9% increase in oil and gas production – in particularly increases in LNG sales – and a softer 2.5% drop in revenue. Total also announced that it would be selling off US$5 billion in assets through 2020 to keep a lid on debt after agreeing to purchase Anadarko Petroleum’s African assets for US$8.8 billion through Occidental.

As with Total, weaker crude prices were the common factor in Q219 results in the industry, though the exact extent differed. Russia’s Gazprom posted higher revenue and higher net profits, while Norway’s Equinor reported falls in both revenue and net profits – leading it to slash investment plans for the year. American producer ConocoPhillips’ quarterly profits and revenue were flat year-on-year, while Italy’s Eni – which has seen major success in Africa – reported flat revenue but lower profits.

 After several quarters of disappointing analysts, ExxonMobil managed to beat expectations in Q219 – recording better-than-expected net profits of US$3.1 billion. In comparison, Shell – which has outperformed ExxonMobil over the past few reporting periods – disappointed the market with net profits halving to US$3 billion from US$6 billion in Q218. The weak performance was attributed (once again) to lower crude prices, as well as lower refining margins. BP, however, managed to beat expectations with net profits of US$2.8 billion, on par with its performance in Q218. But the supermajor king of the quarter was Chevron, with net profits of US$4.3 billion from gains in Permian production, as well as the termination fee from Anadarko after the latter walked away from a buyout deal in favour of Occidental.

And then, there was a surprise. In a rare move, Saudi Aramco – long reputed to be the world’s largest and most profitable energy firm – published its earnings report for 1H19, which is its first ever. The results confirmed what the industry had long accepted as fact: net profit was US$46.9 billion. If split evenly, Aramco’s net profits would be more than the five supermajors combined in Q219. Interestingly, Aramco also divulged that it had paid out US$46.4 billion in dividends, or 99% of its net profit. US$20 billion of that dividend was paid to its principle shareholder – the government of Saudi Arabia – up from US$6 billion in 1H18, which makes for interesting reading to potential investors as Aramco makes a second push for an IPO. With Saudi Aramco CFO Khalid al-Dabbagh announcing that the company was ‘ready for the IPO’ during its first ever earnings call, this reporting paves the way to the behemoth opening up its shares to the public. But all the deep reservoirs in the world did not shield Aramco from market forces. As it led the way in adhering to the OPEC+ club’s current supply restrictions, weaker crude prices saw net profit fall by 11.5% from US$53 billion a year earlier.

So, it’s been a mixed bunch of results this quarter – which perhaps showcases the differences in operational strategies of the world’s oil and gas companies. There is no danger of financials heading into the red any time soon, but without a rising tide of crude prices, Q219 simply shows that though the challenges facing the industry are the same, their approaches to the solutions still differ.

Supermajor Financials: Q2 2019

  • ExxonMobil – Revenue (US$69.1 billion, down 6% y-o-y), Net profit (US$3.1 billion, down 22.5% y-o-y)
  • Shell - Revenue (US$90.5 billion, down 6.5% y-o-y), Net profit (US$3 billion, down 50% y-o-y)
  • Chevron – Revenue (US$36.3 billion, down 10.4% y-o-y), Net profit (US$4.3 billion, up 26% y-o-y)
  • BP - Revenue (US$73.7 billion, down 4.11% y-o-y), Net profit (US$2.8 billion, flat y-o-y)
  • Total - Revenue (US$51.2 billion, down 2.5% y-o-y), Net profit (US$2.89 billion, down 18.6% y-o-y)
August, 14 2019
TODAY IN ENERGY: Australia is on track to become world’s largest LNG exporter

LNG exports from selected countries

Source: U.S. Energy Information Administration, CEDIGAZ, Global Trade Tracker

Australia is on track to surpass Qatar as the world’s largest liquefied natural gas (LNG) exporter, according to Australia’s Department of Industry, Innovation, and Science (DIIS). Australia already surpasses Qatar in LNG export capacity and exported more LNG than Qatar in November 2018 and April 2019. Within the next year, as Australia’s newly commissioned projects ramp up and operate at full capacity, EIA expects Australia to consistently export more LNG than Qatar.

Australia’s LNG export capacity increased from 2.6 billion cubic feet per day (Bcf/d) in 2011 to more than 11.4 Bcf/d in 2019. Australia’s DIIS forecasts that Australian LNG exports will grow to 10.8 Bcf/d by 2020–21 once the recently commissioned Wheatstone, Ichthys, and Prelude floating LNG (FLNG) projects ramp up to full production. Prelude FLNG, a barge located offshore in northwestern Australia, was the last of the eight new LNG export projects that came online in Australia in 2012 through 2018 as part of a major LNG capacity buildout.

Australia LNG export capacity

Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL), trade press
Note: Project’s online date reflects shipment of the first LNG cargo. North West Shelf Trains 1–2 have been in operation since 1989, Train 3 since 1992, Train 4 since 2004, and Train 5 since 2008.

Starting in 2012, five LNG export projects were developed in northwestern Australia: onshore projects Pluto, Gorgon, Wheatstone, and Ichthys, and the offshore Prelude FLNG. The total LNG export capacity in northwestern Australia is now 8.1 Bcf/d. In eastern Australia, three LNG export projects were completed in 2015 and 2016 on Curtis Island in Queensland—Queensland Curtis, Gladstone, and Australia Pacific—with a combined nameplate capacity of 3.4 Bcf/d. All three projects in eastern Australia use natural gas from coalbed methane as a feedstock to produce LNG.

Australia LNG projects

Source: U.S. Energy Information Administration

Most of Australia’s LNG is exported under long-term contracts to three countries: Japan, China, and South Korea. An increasing share of Australia’s LNG exports in recent years has been sent to China to serve its growing natural gas demand. The remaining volumes were almost entirely exported to other countries in Asia, with occasional small volumes exported to destinations outside of Asia.

Australia LNG exports by destination country

Source: U.S. Energy Information Administration, based on International Group of Liquefied Natural Gas Importers (GIIGNL)

For several years, Australia’s natural gas markets in eastern states have been experiencing natural gas shortages and increasing prices because coal-bed methane production at some LNG export facilities in Queensland has not been meeting LNG export commitments. During these shortfalls, project developers have been supplementing their own production with natural gas purchased from the domestic market. The Australian government implemented several initiatives to address domestic natural gas production shortages in eastern states.

Several private companies proposed to develop LNG import terminals in southeastern Australia. Of the five proposed LNG import projects, Port Kembla LNG (proposed import capacity of 0.3 Bcf/d) is in the most advanced stage, having secured the necessary siting permits and an offtake contract with Australian customers. If built, the Port Kembla project will use the floating storage and regasification unit (FSRU) Höegh Galleon starting in January 2021.

August, 14 2019