Adrin Shafil

Petrofac Drilling and Completions Manager
Last Updated: August 25, 2017
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Drilling & Completions
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I used to be a pure red blooded driller. Red, the colour of fire and blood, associated with energy, war, danger, strength, power, determination as well as passion, desire, and love. And all of that hot emotions was for my passion to drill. I did not care about anything else other than well length, cost, time, and how great I was at selecting the right tool, using it and of course telling people about my accomplishments. And in Feb 2004, I reached the very pinnacle of being a drilling engineer. I drilled, single handedly (that shall go in my future memoirs), the longest well in Malaysia. At 6313mMD, I, the lead drilling engineer, held the Malaysian record for longest well ever drilled.

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Unfortunately that intense self admiration and jubilation was short lived, when in a few weeks that record was broken by another operator. My ego deflated, my self worth diminishing by every mention of the other well's length, I banged my forehead whenever I thought of them who beat my record by a measly 50m. And of course, being a red blooded driller, the only lesson I learned was to just to drill longer next time. If I ever drilled another record breaking well, I will make sure I just put in some contingency shale drilling of about ~60m, so that I never get beaten again -_-

Sadly, I have never had a chance again, because since 2004, there have only been a handful of ultra ERD wells drilled. To put this into perspective, the longest well currently in Malaysia was drilled in 2014 to ~6700m, which is a laudable achievement, but exemplifies a slow progression over 10 years. As a driller, I feel that it is my responsibility to revive the interest in ERD and invigorate the passion for world class records which has since waned in the Malay Basin.

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But now I've since gone to the Dark Side (Star Wars trademark), the side that bleeds hydrocarbon, I realise that my previous infatuation with drilling KPIs just seems so irrelevant in the grand scheme of things, when the oil business bottom line are production and profits, and doesn't really give a hoot on how long a well is. To stay profitable, and as reserves become even smaller and difficult to access, it has becomes an ever-more important to focus on looking at several concepts with enabling techniques, to be able to select the right solution to exploit hydrocarbons. As a driller, nothing is sexier and more elegant than suggesting extended reach drilling. While its the most straightforward option which allows the ability to explore and produce further and deeper, and minimise facilities installation, it does come with added risk and possibility of failure.

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Any solution proposed requires capital expenditure. And capital expenditure proposals must be sufficiently specific to permit their technical and commercial justification, with sufficient risk assessment, for exploration and production operations, not just for the immediate fiscal year, but the life of the production sharing contract or field. In the economic phase of evaluation, oil management may find that it has more investment opportunities than capital to invest, or more capital to invest than investment opportunities. Whichever situation exists, oil management needs to resort to some economic criteria for selecting or rejecting investment proposals. Management’s decision in either case is likely to be based largely on the measures of financial return on the investment. In the current depressed oil price climate, how do we make extended reach drilling a viable option?

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I won’t pretend that I’m an expert at economics like Wally in the Dilbert strip above, but let’s try to simplify the concept for the purpose of this article. Lets just say, all of the KPIs of a well, production, cost, schedule, IRR, ROI, terms of PSC, can all be rolled into a variable limit, the economic threshold of the project.

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This chart represents the likelihood of costs in a normal Monte Carlo S-curve spread, where the cost of a project is typically quoted as the P50, with a range given for sensitivities. In layman's terms, the mid case is the P50 (50% chance having costs below that threshold) and P10 and P90 is the low and high side respectively. The range of costs are given so that the project can be carefully evaluated against the returns for any given scenario.

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However, most projects focus on the most straightforward approach, which is trying to reduce base cost ('What we plan for' curve), in an attempt to get closer to the low side, and hope that nothing goes wrong to upset the cart and skew to the upside. To shift the whole S-curve downwards, the team will negotiate contracts, purchase cheaper tangibles/consumables, reduce the technology, and try to get the work done with a lean operation. However, as we lower down our price point, we will inevitably be introducing creep, compromising quality and safety. Post experiencing a trainwreck, the looming result is cost inadvertently passing the economic threshold ('What will actually happen' curve).

A prudent project manager should try to visualise, manage and contain all of the outcomes, trying to put a cap on the risk and exposure of the upside, while making the likelihood of meeting the P50 expectation more likely, even if it means increasing the mid-case, and forgoing a more aggressive P10 ('What we actually need' Green curve). To put it simply, don't lose the farm while trying to save every single dollar.

If you are planning to justify a new technology, a new technique, or a risky proposition such as extended reach drilling, there are 5 key elements that you need in your proposal, to emulate the 'What we actually need' green curve:

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Key 1: Collaborate and Build the knowledge of your team: Collaborate as much as possible internally, and externally with partners, host government, increase data trade transactions, and engage professional networks in order to learn as much as you can on the venture you are undertaking. In this environment, you will be pleasantly surprised that others might actually be interested to learn from you to. In my previous life, I was part of an assurance team, called upon by our partner in Western Australia to look at their concept work. They were down to two options, where they were weighing a 10km ERD well versus a subsea development, where the costs of subsea were 50% higher. The upside costs presented by the drilling team for the ERD looked reasonable, with their P90 costs about a wash with the subsea well. So on paper, ERD looked to be the right selection. However, the Drilling Manager confessed that despite the economics and his attempt to show the risks, he believes that his team does not have the capability to carry out the work, in other words the drillability due to the capability was questionable. The ERD well was dropped in favor of the subsea well, and everybody agreed that was the right call, because regardless what the evaluation on paper shows, there was no confidence in the team that was to carry the work out. Pity.

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Key 2: Cap your upside costs: Gone are the days when people say, "A well is going to cost what its going to cost". Have savvier contracts, such as with lump sum capped, performance incentivised, meterage measured or even turnkeyed contract. We should no longer be dependent on time based contracts, just because the supplier says so. Determine the cost structure which fits your project and design your contracts to meet what is required

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Key 3: Increase your execution reliability: This doesn't mean not having problems. What it means is being able to deliver what you promised. So if the design is complex, and on average non productive time is high, design the lower complexity aspects of the project to absorb the possible problems that you will eventually have. Sometimes you have to accept that your planned costs would have to be higher to increase reliability. Justify the increase and plan for success, but be ready for failure.

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Key 4: Have contingency plans for everything, even failure of your base plan: It goes without saying that risk assessments are the support system for a project, but without closing out and implementing any of the mitigation plans, the risk assessment are just a waste of time. An always think of what would happen if the primary plan fails? Do you have a fall back plan to still retain value or limit exposure? An alternative target, perhaps? A ready for deployment sidetrack assembly?

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Key 5: Increase the value statement of your design: During detailed design, a D&C team often gets carried away on focusing too much on 'getting the job' done versus remembering why the job was done in the first place. Reaching an objective is just the means to extract the value from the project. Design the well in order to increase the returns on the project, and increase the economic threshold. Drill better wells, which doesn't necessarily mean drilling longer or more wells.

Hopefully the keys above will assist the reader in creating more palatable ERD proposals. Every single project, every single team, and every single company will have a different approach in creating value, but I do hope that maybe in some minute way, I managed to jog some life back into excitement about drilling and ERD in Malaysia. Stay savvy, people.

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The Impact of COVID 19 In The Downstream Oil & Gas Sector

Recent headlines on the oil industry have focused squarely on the upstream side: the amount of crude oil that is being produced and the resulting effect on oil prices, against a backdrop of the Covid-19 pandemic. But that is just one part of the supply chain. To be sold as final products, crude oil needs to be refined into its constituent fuels, each of which is facing its own crisis because of the overall demand destruction caused by the virus. And once the dust settles, the global refining industry will look very different.

Because even before the pandemic broke out, there was a surplus of refining capacity worldwide. According to the BP Statistical Review of World Energy 2019, global oil demand was some 99.85 mmb/d. However, this consumption figure includes substitute fuels – ethanol blended into US gasoline and biodiesel in Europe and parts of Asia – as well as chemical additives added on to fuels. While by no means an exact science, extrapolating oil demand to exclude this results in a global oil demand figure of some 95.44 mmb/d. In comparison, global refining capacity was just over 100 mmb/d. This overcapacity is intentional; since most refineries do not run at 100% utilisation all the time and many will shut down for scheduled maintenance periodically, global refining utilisation rates stand at about 85%.

Based on this, even accounting for differences in definitions and calculations, global oil demand and global oil refining supply is relatively evenly matched. However, demand is a fluid beast, while refineries are static. With the Covid-19 pandemic entering into its sixth month, the impact on fuels demand has been dramatic. Estimates suggest that global oil demand fell by as much as 20 mmb/d at its peak. In the early days of the crisis, refiners responded by slashing the production of jet fuel towards gasoline and diesel, as international air travel was one of the first victims of the virus. As national and sub-national lockdowns were introduced, demand destruction extended to transport fuels (gasoline, diesel, fuel oil), petrochemicals (naphtha, LPG) and  power generation (gasoil, fuel oil). Just as shutting down an oil rig can take weeks to complete, shutting down an entire oil refinery can take a similar timeframe – while still producing fuels that there is no demand for.

Refineries responded by slashing utilisation rates, and prioritising certain fuel types. In China, state oil refiners moved from running their sites at 90% to 40-50% at the peak of the Chinese outbreak; similar moves were made by key refiners in South Korea and Japan. With the lockdowns easing across most of Asia, refining runs have now increased, stimulating demand for crude oil. In Europe, where the virus hit hard and fast, refinery utilisation rates dropped as low as 10% in some cases, with some countries (Portugal, Italy) halting refining activities altogether. In the USA, now the hardest-hit country in the world, several refineries have been shuttered, with no timeline on if and when production will resume. But with lockdowns easing, and the summer driving season up ahead, refinery production is gradually increasing.

But even if the end of the Covid-19 crisis is near, it still doesn’t change the fundamental issue facing the refining industry – there is still too much capacity. The supply/demand balance shows that most regions are quite even in terms of consumption and refining capacity, with the exception of overcapacity in Europe and the former Soviet Union bloc. The regional balances do hide some interesting stories; Chinese refining capacity exceeds its consumption by over 2 mmb/d, and with the addition of 3 new mega-refineries in 2019, that gap increases even further. The only reason why the balance in Asia looks relatively even is because of oil demand ‘sinks’ such as Indonesia, Vietnam and Pakistan. Even in the US, the wealth of refining capacity on the Gulf Coast makes smaller refineries on the East and West coasts increasingly redundant.

Given this, the aftermath of the Covid-19 crisis will be the inevitable hastening of the current trend in the refining industry, the closure of small, simpler refineries in favour of large, complex and more modern refineries. On the chopping block will be many of the sub-50 kb/d refineries in Europe; because why run a loss-making refinery when the product can be imported for cheaper, even accounting for shipping costs from the Middle East or Asia? Smaller US refineries are at risk as well, along with legacy sites in the Middle East and Russia. Based on current trends, Europe alone could lose some 2 mmb/d of refining capacity by 2025. Rising oil prices and improvements in refining margins could ensure the continued survival of some vulnerable refineries, but that will only be a temporary measure. The trend is clear; out with the small, in with the big. Covid-19 will only amplify that. It may be a painful process, but in the grand scheme of things, it is also a necessary one.

Infographic: Global oil consumption and refining capacity (BP Statistical Review of World Energy 2019)

Region
Consumption (mmb/d)*
Refining Capacity (mmb/d)
North America

22.71

22.33

Latin America

6.5

5.98

Europe

14.27

15.68

CIS

4.0

8.16

Middle East

9.0

9.7

Africa

3.96

3.4

Asia-Pacific

35

34.75

Total

95.44

100.05

*Extrapolated to exclude additives and substitute fuels (ethanol, biodiesel)

Market Outlook:

  • Crude price trading range: Brent – US$33-37/b, WTI – US$30-33/b
  • Crude oil prices hold their recent gains, staying rangebound with demand gradually improving as lockdown slowly ease
  • Worries that global oil supply would increase after June - when the OPEC+ supply deal eases and higher prices bring back some free-market production - kept prices in check
  • Russia has signalled that it intends to ease back immediately in line with the supply deal, but Saudi Arabia and its allies are pushing for the 9.7 mmb/d cut to be extended to end-2020, putting the two oil producers on another collision course that previously resulted in a price war
  • Morgan Stanley expects Brent prices to rise to US$40/b by 4Q 2020, but cautioned that a full recovery was only likely to materialise in 2021

End of Article

In this time of COVID-19, we have had to relook at the way we approach workplace learning. We understand that businesses can’t afford to push the pause button on capability building, as employee safety comes in first and mistakes can be very costly. That’s why we have put together a series of Virtual Instructor Led Training or VILT to ensure that there is no disruption to your workplace learning and progression.

Find courses available for Virtual Instructor Led Training through latest video conferencing technology.

May, 31 2020
North American crude oil prices are closely, but not perfectly, connected

selected North American crude oil prices

Source: U.S. Energy Information Administration, based on Bloomberg L.P. data
Note: All prices except West Texas Intermediate (Cushing) are spot prices.

The New York Mercantile Exchange (NYMEX) front-month futures contract for West Texas Intermediate (WTI), the most heavily used crude oil price benchmark in North America, saw its largest and swiftest decline ever on April 20, 2020, dropping as low as -$40.32 per barrel (b) during intraday trading before closing at -$37.63/b. Prices have since recovered, and even though the market event proved short-lived, the incident is useful for highlighting the interconnectedness of the wider North American crude oil market.

Changes in the NYMEX WTI price can affect other price markers across North America because of physical market linkages such as pipelines—as with the WTI Midland price—or because a specific price is based on a formula—as with the Maya crude oil price. This interconnectedness led other North American crude oil spot price markers to also fall below zero on April 20, including WTI Midland, Mars, West Texas Sour (WTS), and Bakken Clearbrook. However, the usefulness of the NYMEX WTI to crude oil market participants as a reference price is limited by several factors.

pricing locations of selected North American crudes

Source: U.S. Energy Information Administration

First, NYMEX WTI is geographically specific because it is physically redeemed (or settled) at storage facilities located in Cushing, Oklahoma, and so it is influenced by events that may not reflect the wider market. The April 20 WTI price decline was driven in part by a local deficit of uncommitted crude oil storage capacity in Cushing. Similarly, while the price of the Bakken Guernsey marker declined to -$38.63/b, the price of Louisiana Light Sweet—a chemically comparable crude oil—decreased to $13.37/b.

Second, NYMEX WTI is chemically specific, meaning to be graded as WTI by NYMEX, a crude oil must fall within the acceptable ranges of 12 different physical characteristics such as density, sulfur content, acidity, and purity. NYMEX WTI can therefore be unsuitable as a price for crude oils with characteristics outside these specific ranges.

Finally, NYMEX WTI is time specific. As a futures contract, the price of a NYMEX WTI contract is the price to deliver 1,000 barrels of crude oil within a specific month in the future (typically at least 10 days). The last day of trading for the May 2020 contract, for instance, was April 21, with physical delivery occurring between May 1 and May 31. Some market participants, however, may prefer more immediate delivery than a NYMEX WTI futures contract provides. Consequently, these market participants will instead turn to shorter-term spot price alternatives.

Taken together, these attributes help to explain the variety of prices used in the North American crude oil market. These markers price most of the crude oils commonly used by U.S. buyers and cover a wide geographic area.

Principal contributor: Jesse Barnett

May, 28 2020
Financial Review: 2019

Key findings

  • Brent crude oil daily average prices were $64.16 per barrel in 2019—11% lower than 2018 levels
  • The 102 companies analyzed in this study increased their combined liquids and natural gas production 2% from 2018 to 2019
  • Proved reserves additions in 2019 were about the same as the 2010–18 annual average
  • Finding plus lifting costs increased 13% from 2018 to 2019
  • Occidental Petroleum’s acquisition of Anadarko Petroleum contributed to the largest reserve acquisition costs incurred for the group of companies since 2016
  • Refiners’ earnings per barrel declined slightly from 2018 to 2019

See entire annual review

May, 26 2020