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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Brazil Needs a “Makeover” For Future Bids

The year’s final upstream auctions were touted as a potential bonanza for Brazil, with pre-auction estimates suggesting that up to US$50 billion could be raised for some deliciously-promising blocks. The Financial Times expected it to be the ‘largest oil bidding round in history’. The previous auction – held in October – was a success, attracting attention from supermajors and new entrants, including Malaysia’s Petronas. Instead, the final two auctions in November were a complete flop, with only three of the nine major blocks awarded.

What happened? What happened to the appetite displayed by international players such as ExxonMobil, Shell, Chevron, Total and BP in October? The fields on offer are certainly tempting, located in the prolific pre-salt basin and including prized assets such as the Buzios, Itapu, Sepia and Atapu fields. Collectively, the fields could contain as much as 15 billion barrels of crude oil. Time-to-market is also shorter; much of the heavy work has already been done by Petrobras during the period where it was the only firm allowed to develop Brazil’s domestic pre-salt fields. But a series of corruption scandals and a new government has necessitated a widening of that ambition, by bringing in foreign expertise and, more crucially, foreign money. But the fields won’t come cheap. In addition to signing bonuses to be paid to the Brazilian state ranging from US$331 million to US$17 billion by field, compensation will need to be paid to Petrobras. The auction isn’t a traditional one,  but a Transfer of Rights sale covering existing in-development and producing fields.

And therein lies the problem. The massive upfront cost of entry comes at a time when crude oil prices are moderating and the future outlook of the market is uncertain, with risks of trade wars, economic downturns and a move towards clean energy. The fact that the compensation to be paid to Petrobras would be negotiated post-auction was another blow, as was the fact that the auction revolved around competing on the level of profit oil offered to the Brazilian government. Prior to the auction itself, this arrangement was criticised as overtly complicated and ‘awful’, with Petrobras still retaining the right of first refusal to operate any pre-salt fields A simple concession model was suggested as a better alternative, and the stunning rebuke by international oil firms at the auction is testament to that. The message is clear. If Brazil wants to open up for business, it needs to leave behind its legacy of nationalisation and protectionism centring around Petrobras. In an ironic twist, the only fields that were awarded went to Petrobras-led consortiums – essentially keeping it in the family.

There were signs that it was going to end up this way. ExxonMobil – so enthusiastic in the October auction – pulled out of partnering with Petrobras for Buzios, balking at the high price tag despite the field currently producing at 400,000 b/d. But the full-scale of the reticence revealed flaws in Brazil’s plans, with state officials admitting to being ‘stunned’ by the lack of participation. Comments seem to suggest that Brazil will now re-assess how it will offer the fields when they go up for sale again next year, promising to take into account the reasons that scared international majors off in the first place. Some US$17 billion was raised through the two days of auction – not an insignificant amount but a far cry from the US$50 billion expected. The oil is there. Enough oil to vault Brazil’s production from 3 mmb/d to 7 mmb/d by 2030. All Brazil needs to do now is create a better offer to tempt the interested parties.

Results of Brazil’s November upstream auctions:

  • 6 November: Four blocks on offer, two awarded (Buzios, 90% Petrobras 5% CNOOC 5% CNODC ; Itapu, 100% Petrobras)
  • 7 November: Five blocks on offer, one awarded (Aram, 80% Petrobras 20% CNOOC)
November, 14 2019
Short-Term Energy Outlook

Highlights  

Global liquid fuels

  • Brent crude oil spot prices averaged $60 per barrel (b) in October, down $3/b from September and down $21/b from October 2018. EIA forecasts Brent spot prices will average $60/b in 2020, down from a 2019 average of $64/b. EIA forecasts that West Texas Intermediate (WTI) prices will average $5.50/b less than Brent prices in 2020. EIA expects crude oil prices will be lower on average in 2020 than in 2019 because of forecast rising global oil inventories, particularly in the first half of next year.
  • Based on preliminary data and model estimates, EIA estimates that the United States exported 140,000 b/d more total crude oil and petroleum products in September than it imported; total exports exceeded imports by 550,000 b/d in October. If confirmed in survey-collected monthly data, it would be the first time the United States exported more petroleum than it imported since EIA records began in 1949. EIA expects total crude oil and petroleum net exports to average 750,000 b/d in 2020 compared with average net imports of 520,000 b/d in 2019.
  • Distillate fuel inventories (a category that includes home heating oil) in the U.S. East Coast—Petroleum Administration for Defense District (PADD 1)—totaled 36.6 million barrels at the end of October, which was 30% lower than the five-year (2014–18) average for the end of October. The declining inventories largely reflect low U.S. refinery runs during October and low distillate fuel imports to the East Coast. EIA does not forecast regional distillate prices, but low inventories could put upward pressure on East Coast distillate fuel prices, including home heating oil, in the coming weeks.
  • U.S. regular gasoline retail prices averaged $2.63 per gallon (gal) in October, up 3 cents/gal from September and 11 cents/gal higher than forecast in last month’s STEO. Average U.S. regular gasoline retail prices were higher than expected, in large part, because of ongoing issues from refinery outages in California. EIA forecasts that regular gasoline prices on the West Coast (PADD 5), a region that includes California, will fall as the issues begin to resolve. EIA expects that prices in the region will average $3.44/gal in November and $3.12/gal in December. For the U.S. national average, EIA expects regular gasoline retail prices to average $2.65/gal in November and fall to $2.50/gal in December. EIA forecasts that the annual average price in 2020 will be $2.62/gal.
  • Despite low distillate fuel inventories, EIA expects that average household expenditures for home heating oil will decrease this winter. This forecast largely reflects warmer temperatures than last winter for the entire October–March period, and retail heating oil prices are expected to be unchanged compared with last winter. For households that heat with propane, EIA forecasts that expenditures will fall by 15% from last winter because of milder temperatures and lower propane prices.


Natural gas

  • Natural gas storage injections in the United States outpaced the previous five-year (2014–18) average during the 2019 injection season as a result of rising natural gas production. At the beginning of April, when the injection season started, working inventories were 28% lower than the five-year average for the same period. By October 31, U.S. total working gas inventories reached 3,762 billion cubic feet (Bcf), which was 1% higher than the five-year average and 16% higher than a year ago.
  • EIA expects natural gas storage withdrawals to total 1.9 trillion cubic feet (Tcf) between the end of October and the end of March, which is less than the previous five-year average winter withdrawal. Withdrawal of this amount would leave end-of-March inventories at almost 1.9 Tcf, 9% higher than the five-year average.
  • The Henry Hub natural gas spot price averaged $2.33 per million British thermal units (MMBtu) in October, down 23 cents/MMBtu from September. The decline largely reflected strong inventory injections. However, forecast cold temperatures across much of the country caused prices to rise in early November, and EIA forecasts Henry Hub prices to average $2.73/MMBtu for the final two months of 2019. EIA forecasts Henry Hub spot prices to average $2.48/MMBtu in 2020, down 13 cents/MMBtu from the 2019 average. Lower forecast prices in 2020 reflect a decline in U.S. natural gas demand and slowing U.S. natural gas export growth, allowing inventories to remain higher than the five-year average during the year even as natural gas production growth is forecast to slow.
  • EIA forecasts that annual U.S. dry natural gas production will average 92.1 billion cubic feet per day (Bcf/d) in 2019, up 10% from 2018. EIA expects that natural gas production will grow much less in 2020 because of the lag between changes in price and changes in future drilling activity, with low prices in the third quarter of 2019 reducing natural gas-directed drilling in the first half of 2020. EIA forecasts natural gas production in 2020 will average 94.9 Bcf/d.
  • EIA expects U.S. liquefied natural gas (LNG) exports to average 4.7 Bcf/d in 2019 and 6.4 Bcf/d in 2020 as three new liquefaction projects come online. In 2019, three new liquefaction facilities—Cameron LNG, Freeport LNG, and Elba Island LNG—commissioned their first trains. Natural gas deliveries to LNG projects set a new record in July, averaging 6.0 Bcf/d, and increased further to 6.6 Bcf/d in October, when new trains at Cameron and Freeport began ramping up. Cameron LNG exported its first cargo in May, Corpus Christi LNG’s newly commissioned Train 2 in July, and Freeport in September. Elba Island plans to ship its first export cargo by the end of this year. In 2020, Cameron, Freeport, and Elba Island expect to place their remaining trains in service, bringing the total U.S. LNG export capacity to 8.9 Bcf/d by the end of the year.


Electricity, coal, renewables, and emissions

  • EIA expects the share of U.S. total utility-scale electricity generation from natural gas-fired power plants will rise from 34% in 2018 to 37% in 2019 and to 38% in 2020. EIA forecasts the share of U.S. electric generation from coal to average 25% in 2019 and 22% in 2020, down from 28% in 2018. EIA’s forecast nuclear share of U.S. generation remains at about 20% in 2019 and in 2020. Hydropower averages a 7% share of total U.S. generation in the forecast for 2019 and 2020, down from almost 8% in 2018. Wind, solar, and other nonhydropower renewables provided 9% of U.S. total utility-scale generation in 2018. EIA expects they will provide 10% in 2019 and 12% in 2020.
  • EIA expects total U.S. coal production in 2019 to total 698 million short tons (MMst), an 8% decrease from the 2018 level of 756 MMst. The decline reflects lower demand for coal in the U.S. electric power sector and reduced competitiveness of U.S. exports in the global market. EIA expects U.S. steam coal exports to face increasing competition from Eastern European sources, and that Russia will fill a growing share of steam coal trade, causing U.S. coal exports to fall in 2020. EIA forecasts that coal production in 2020 will total 607 MMst.
  • EIA expects U.S. electric power sector generation from renewables other than hydropower—principally wind and solar—to grow from 408 billion kilowatthours (kWh) in 2019 to 466 billion kWh in 2020. In EIA’s forecast, Texas accounts for 19% of the U.S. nonhydropower renewables generation in 2019 and 22% in 2020. California’s forecast share of nonhydropower renewables generation falls from 15% in 2019 to 14% in 2020. EIA expects that the Midwest and Central power regions will see shares in the 16% to 18% range for 2019 and 2020.
  • EIA forecasts that, after rising by 2.7% in 2018, U.S. energy-related carbon dioxide (CO2) emissions will decline by 1.7% in 2019 and by 2.0% in 2020, partially as a result of lower forecast energy consumption. In 2019, EIA forecasts less demand for space cooling because of cooler summer months; an expected 5% decline in cooling degree days from 2018, when it was significantly higher than the previous 10-year (2008–17) average. In addition, EIA also expects U.S. CO2 emissions in 2019 to decline because the forecast share of electricity generated from natural gas and renewables will increase, and the share generated from coal, which is a more carbon-intensive energy source, will decrease.
November, 14 2019
The U.S. placed near-record volumes of natural gas in storage this injection season

The amount of natural gas held in storage in 2019 went from a relatively low value of 1,155 billion cubic feet (Bcf) at the beginning of April to 3,724 Bcf at the end of October because of near-record injection activity during the natural gas injection, or refill, season (April 1–October 31). Inventories as of October 31 were 37 Bcf higher than the previous five-year end-of-October average, according to interpolated values in the U.S. Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report.

Although the end of the natural gas storage injection season is traditionally defined as October 31, injections often occur in November. Working natural gas stocks ended the previous heating season at 1,155 Bcf on March 31, 2019—the second-lowest level for that time of year since 2004. The 2019 injection season included several weeks with relatively high injections: weekly changes exceeded 100 Bcf nine times in 2019. Certain weeks in April, June, and September were the highest weekly net injections in those months since at least 2010.

weekly net changes in natural gas storage

Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report

From April 1 through October 31, 2019, more than 2,569 Bcf of natural gas was placed into storage in the Lower 48 states. This volume was the second-highest net injected volume for the injection season, falling short of the record 2,727 Bcf injected during the 2014 injection season. In 2014, a particularly cold winter left natural gas inventories in the Lower 48 states at 837 Bcf—the lowest level for that time of year since 2003.

November, 11 2019