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Last Updated: January 15, 2020
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To operate well is to operate responsibly—but more must be done on sustainable design and balanced portfolios to achieve a net-zero future.

Hydrocarbons have powered economic growth for 150 years, but their emissions are destabilizing the earth’s climate. Now that the atmospheric impact of fossil fuels is widely recognized, the sector is under increasing pressure. Policy makers, investors, and society are pressing for change, threatening operators’ license to operate.

Operators have responded with strategic convening and conspicuous investments in innovation and diversification. Yet they have barely begun to address the 4.1 GtCO2e of emissions—almost 10 percent of all anthropogenic greenhouse gas—created every year by their own operations, two-thirds of it from upstream.

Technologies to decarbonize the extraction and production of hydrocarbons already exist and many are economically viable, yet the sector’s atmospheric emissions continue to rise. This paper explores why there has been little change so far, and shows how, with a bold vision and the determination to act, the oil and gas sector can step on a different path, an energy pathway that can contribute to limiting the rise in average global temperatures to 1.5°C.


Why so much greenhouse gas? A trio of emission-intensity drivers

Studying the emission intensity of upstream oil and gas assets reveals that three structural factors drive their “well to pipe” emission intensity.


First, resource complexity structurally sets an asset’s emission intensity

All else being equal, the least emission-intensive assets are large producers with high API gravity and low reservoir complexity. The data show that assets with API gravity of 20° or less can be, on average, three times more emission-intensive than those with API gravity of 50° or more. Assets with the highest structural emission intensity in our data set are complex reservoirs: viscous, in deep or ultra-deep water, compartmentalized, or high pressure and temperature. Pressure maintenance during primary production or secondary and tertiary recovery also increases energy and emission intensity. Simulations of GHG emissions from oil production show average emissions doubling over 25 years. In the IEA’s terminology, these are resources with intrinsically low energy return on energy invested (EROI).


Second, processes and engineering are crucial controllable drivers

Complex facilities are typically more energy-intensive, and therefore more emission-intensive. Hub platforms with more equipment and personnel require more energy for running core and auxiliary systems, while high manning levels intensify their logistics, which again increases emissions. A small single-steel-jacket platform is less emission-intensive than an FPSO with complex subsea export infrastructure connecting many complex wells.

Operations benchmarks—and our emission data—both show that the age of a production facility does not limit operational performance. However, older assets face more complex challenges in reducing emission intensity. Older equipment may be less efficient and economically challenging to replace. Aging production facilities may also suffer from higher fugitive emissions as wear parts degrade. On the other hand, process design choices can help offset the challenges of maturity.


Third, routine flaring and venting, if prevalent, can contribute 40 percent of the carbon intensity of hydrocarbon production in a region

In jurisdictions where venting and flaring are still common, such as Russia, Iran, the United States, Algeria, and Nigeria, oil facilities with high gas-to-oil ratios and few export or recovery options will routinely flare or vent the associated gas, emitting large volumes of CO2, some methane, and other volatile organic compounds (VOCs). More widely, fugitive emissions and intermittent flaring and venting materially increase upstream methane emissions, which account for 34 percent of oil-production emissions and 41 percent of gas-production emissions, assuming 100-year global-warming potential. This waste is a problem, but its mitigation presents an economic opportunity.


So what is to be done? The path to decarbonization of upstream operations

In the short term, the structural drivers of emission intensity seem to limit the freedom upstream leaders have to reduce their atmospheric emissions. For producing assets, these constraints appear to be the hand they have been dealt. However, operators can choose how to play this hand, giving them more ways to reduce emission intensity than at first appear. Our operations benchmarks show that raising operational performance has a large impact on emissions. And 90 percent of known technological solutions to decarbonization are within the grasp of operators at a cost of no more than $50/metric ton of carbon.

We describe three levers to reduce emission intensity across the full spectrum of scope 1 (direct) and scope 2 (indirect) emissions from upstream oil and gas operations (Exhibit 1). The first, indisputable, step is optimizing operations—maximizing stability and uptime reduces intermittent flaring and venting, and requires few major process changes. Second, sustainable design choices are now available for deployment and increasingly present a positive economic benefit. Third, producers must start to balance their portfolios across resources with a spread of emission intensity in anticipation of the risks from future policy scenarios and investor choices.


Exhibit 1



The first decarbonization lever: Optimizing operations

Operating well equals operating responsibly. Above all, it is an economical first step in reducing intermittent flaring and venting and fugitive emissions, the third biggest source of emissions. Our analysis shows that across a global sample, once you correct for structural factors, assets in the top decile of production efficiency have the lowest emissions in the sector, based on the stability of their operations. The best can achieve less than 7 kg per barrel of oil equivalent, whereas assets in the third quartile emit at least three times as much.

To catch up, lower-performing assets must address three areas. First, resolve repeat failures that cause process trips or shutdowns. The flaring or venting of methane and other VOCs as equipment is depressurized for safe maintenance and restart leads to high emission intensity. Second, ensure operating parameters have not diverged significantly from the design envelope due to changes in fluid rates and properties. For example, pumps not running at their best efficiency point not only use more energy, but are also less reliable, both of which lead to higher emissions. Third, find and fix asset-integrity issues that increase fugitive emissions, such as degradation of flange joints, valve glands, or seals.

All three areas can be addressed within current operating models and are the core components of traditional levers to improve operational performance. We observe, on average, that a 10 percent increase in production efficiency delivers a 4 percent reduction in emission intensity, all else being constant. Maximizing stability and integrity may require upgrades of process, controls, and parts. A less capital-intensive route is to leverage data and advanced analytics to help optimize and stabilize operations. Predictive maintenance and automated condition-monitoring can reduce planned interventions and extend runs, improving stability and reducing emissions. Advanced analytics enables the next level of energy efficiency, isolating operating parameters that minimize power per unit throughput.


The second decarbonization lever: Sustainable design

There are multiple sustainable design options to make processes less emission-intensive. However, their use is not yet routine: traditional investment stage gates weight up-front capital costs over other considerations, such as energy efficiency or cost-to-operate. With total life-cycle value as the target function, operators may be more motivated to explore sustainable design. Doing so using proven technologies can not only reduce operating costs, but also generate new revenue streams.

Monetizing wasted gas. By some estimates, 257 bcm of natural gas—equivalent to nearly half the consumption of Europe—is wasted globally in flares, vents, and leaks. If monetized, this could generate nearly $40 billion of revenue globally. New ventures such as Capterio improve data transparency around flaring and install bespoke technological solutions that monetize the gas. Solutions include reinjecting to enhance recovery or disposal, power generation (for own use or grid export), building export routes to destination markets, or installing small-scale converters to create products such as CNG, LPG, GTL or LNG.

Reducing energy demand. Energy costs (including opportunity costs) are close to 15 percent of total production costs; recent work with upstream operators suggests they can save up to 20 percent in energy usage. This makes a compelling business case, with a total prize of up to $10 billion in cost reduction per year for the upstream industry. Modular unmanned installations around a supporting hub, as Norway is building in the NOAKA area, or better still, linked to a remote operations center, are gaining traction. Simpler, modular, and reusable facilities with low equipment counts and manning levels reduce costs and emissions from energy use and logistics.

Using zero-carbon energy supply. Sustainable sources of energy improve conversion efficiencies or generate revenue. Offshore grid-based electrification was first shown to be viable in 2003, when the Abu Safah development, 50 kilometers offshore in Saudi Arabia, started up with a connection to the main grid. More recently, the newly commissioned Johan Sverdrup is powered from shore even though it is 140 kilometers from Stavanger at a water depth of 110 to 120 meters. For more remote platforms, localized renewables generation offers a sustainable design option. Platforms in both the southern North Sea and Norwegian sectors, for instance, have introduced zero-carbon power sources with conventional backup for stand-alone facilities. To improve the economics of their deployment, operators might supply power to clusters of their own and third-party offshore facilities.

Removal through carbon capture, usage, and storage (CCU/S). CCU/S is an increasingly popular decarbonization option as seen in the Norwegian Continental Shelf with an encouraging example of CCU/S collaboration across the industry in the renewed Northern Lights project. When combined with CO2-enhanced recovery, it improves recovery rates in a closed-loop CO2 system and raises both production and emission performance.


The third decarbonization lever: Balanced portfolios

The demands of policy makers and investors are fast evolving. Credible scenarios show shareholders reducing their exposure to high-emitting resources, freezing out operators holding the highest-intensity assets. There are also credible scenarios in which policy and markets accelerate peak oil demand to 2025, thereby raising the cost of capital and making oil and gas unattractive as investments for growth.globall

Integrated oil company portfolios have tilted toward natural gas over the past few years, attracted by its reputation as a transition fuel. More recently, Equinor has announced the ambition to meet a carbon-intensity target of 8 kgCO2e/boe by 2030. Other producers have set emission-reduction targets at varying levels. Bold visions must recognize that the highest-emitting reservoirs are nearly three times more emission-intensive than the lowest-emitting ones. What follows is a set of choices for upstream leaders to make around their field-development plans, resource funnels, and portfolios.

Field-development plans need to weigh recovery factor against the emission performance of different production and pressure maintenance techniques. Likewise, building portfolios with better emission performance would involve high-grading only the lower-intensity resources or those for which sustainable design can fully offset the emission implications of resource complexity. Critical factors are viscosity, water depth, distance from shore, initial pressure, and depletion. If emission intensity were always a decision criterion, or a $50/metric ton carbon price were imputed in shaping resource funnels, investment committees would favor “advantaged” resources—those with higher API gravity, in shallow to medium water or requiring conventional production techniques. Or they might limit offshore investments closer to shore to enable grid-based electrification. The value equation, fortunately, boosts balanced portfolios: breakeven economics of many reservoirs with high emission intensity are marginal at more than $65.


How to make a strong start: The decarbonization fundamentals

Upstream leaders aspiring to reduce emissions must first overcome the uncertainties in understanding the emission performance of their assets and portfolios: what is really driving emissions, which emission sources to tackle urgently, and by how much. We respond to this baselining challenge by drawing on the McKinsey Upstream Energy & Emissions Index (MUEEI), a proprietary upstream energy and emission index of assets of different types and at different life stages. The index brings both consistency and detail, which enable operators to separate the controllable factors in emission intensity across the oil and gas life cycle from the external ones. The following sidebar explains the methodology, using a global sample of offshore assets, and illustrates how to apply the MUEEI in assessing current emission performance and in setting reduction targets.

Decarbonization oil gas upstream McKinsey hydrocarbon MUEEI
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Utility-scale battery storage capacity continued its upward trend in 2018

Utility-scale battery storage systems are increasingly being installed in the United States. In 2010, the United States had seven operational battery storage systems, which accounted for 59 megawatts (MW) of power capacity (the maximum amount of power output a battery can provide in any instant) and 21 megawatthours (MWh) of energy capacity (the total amount of energy that can be stored or discharged by a battery). By the end of 2018, the United States had 125 operational battery storage systems, providing a total of 869 MW of installed power capacity and 1,236 MWh of energy capacity.

Battery storage systems store electricity produced by generators or pulled directly from the electrical grid, and they redistribute the power later as needed. These systems have a wide variety of applications, including integrating renewables into the grid, peak shaving, frequency regulation, and providing backup power.

annual utility-scale battery storage capacity additions by region

Source: U.S. Energy Information Administration, Preliminary Monthly Electric Generator Inventory and Annual Electric Generator Report

Most utility-scale battery storage capacity is installed in regions covered by independent system operators (ISOs) or regional transmission organizations (RTOs). Historically, most battery systems are in the PJM Interconnection (PJM), which manages the power grid in 13 eastern and Midwestern states as well as the District of Columbia, and in the California Independent System Operator (CAISO). Together, PJM and CAISO accounted for 55% of the total battery storage power capacity built between 2010 and 2018. However, in 2018, more than 58% (130 MW) of new storage power capacity additions, representing 69% (337 MWh) of energy capacity additions, were installed in states outside of those areas.

In 2018, many regions outside of CAISO and PJM began adding greater amounts of battery storage capacity to their power grids, including Alaska and Hawaii, the Electric Reliability Council of Texas (ERCOT), and the Midcontinent Independent System Operator (MISO). Many of the additions were the result of procurement requirements, financial incentives, and long-term planning mechanisms that promote the use of energy storage in the respective states. Alaska and Hawaii, which have isolated power grids, are expanding battery storage capacity to increase grid reliability and reduce dependence on expensive fossil fuel imports.

total installed cost of utility-scale battery systems by year

Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report
Note: The cost range represents cost data elements from the 25th to 75th percentiles for each year of reported cost data.

Average costs per unit of energy capacity decreased 61% between 2015 and 2017, dropping from $2,153 per kilowatthour (kWh) to $834 per kWh. The large decrease in cost makes battery storage more economical, helping accelerate capacity growth. Affordable battery storage also plays an important role in the continued integration of storage with intermittent renewable electricity sources such as wind and solar.

Additional information on these topics is available in the U.S. Energy Information Administration’s (EIA) recently updated Battery Storage in the United States: An Update on Market Trends. This report explores trends in battery storage capacity additions and describes the current state of the market, including information on applications, cost, market and policy drivers, and future project developments.

August, 11 2020
The State of the Industry: Q2 2020 Financial Performance

It is, obviously, unsurprising that the recently released Q2 financials for the oil & gas supermajors contained distressed numbers as the first full quarter of Covid-19 impact washed over the entire industry. It is, however, surprising how the various behemoths of the energy world are choosing to respond to the new normal, and how past strategies have exposed either inherent strengths or weakness in their operational strategy.

Let’s begin with BP. With roots that stretch back to 1908 with the discovery of commercial oil in Persia, now Iran – BP arguably coined the phrase supermajor in the late 1990s, when acquisition of Amoco, Arco and Burmah Castrol married BP’s own substantial holdings in Europe and the Middle East to create a transatlantic oil and gas giant. It was a trend mirrored across the industry, with the Seven Sisters of the 1970s becoming ExxonMobil (Esso and Mobil), Chevron (Gulf Oil, Socal and Texaco) and modern day Royal Dutch Shell. Joining them were ConocoPhillips (Conoco and Phillips) and Total (Petrofina and Elf Aquitaine). As the world’s appetite for oil and gas increased at an accelerating pace, the supermajors became among the world’s largest and highest valued companies across the next two decades.

That is now poised for a major change. With fossil fuels waning in demand and renewables becoming more investable, BP is now declaring that it will no longer be a supermajor. CEO Bernard Looney made the announcement ahead of the release of the company’s Q2 financials, seeking to reinvent the firm as ‘integrated energy company’ rather than an ‘integrated oil company’. To make this change, Looney is looking to shrink BP’s oil and gas output by 40% through 2030 and invest heavily to become the world’s largest renewable energy businesses, putting climate change firmly on the agenda and getting ahead of the curve in meeting European directives for a low-carbon future. This was, perhaps, already on the cards. But the Covid-19 effect has hastened it. With a second quarter loss of US$6.7 billion, BP is choosing this time to rebrand itself for long-term transformation rather than maximise current shareholder value; indeed, it will slash dividends in half in order to invest cash for the future.

On the European side of the Atlantic, that trend is accelerating. Shell and Total are also aiming to be carbon neutral by 2050, alongside other European majors such as Eni and Equinor. That isn’t to say that oil or gas will no longer play a huge role in their operations – indeed Total and Eni in particular have made many recent and potentially lucrative finds in Egypt, South Africa and Suriname – just that oil and gas will become a smaller percentage of a diversified business. Both Shell and Total have also displayed how past strategic decisions have paid dividends in uncertain times. Both supermajors declared profits for the quarter, escaping the trend of underlying losses with net profits of US$638 million and US$126 million respectively when a deep red colour to the numbers was expected. The saving grace in a dramatic quarter was their trading activities, where the trading divisions of Shell and Total (as well as BP) took advantage of chaos in the market to deliver strong results. But even with this silver lining, Shell and Total are scaling back on dividends, as they join BP in a drive to diversify in the age of climate change, which has strong political backing in Europe where they are based.

On the other side of the pond, the mood surrounding climate change is decidedly different. ExxonMobil and Chevron aren’t exactly ignoring a low-carbon future but they aren’t exactly embracing it wholeheartedly either. Instead, both supermajors look to be focusing on maximising shareholder value by focusing on producing oil as profitably as possible. It explains why Chevron moved to acquire Noble Energy recently after failing to buy Anadarko last year, and why ExxonMobil is still gung-ho over American shale and its new found black gold assets in Guyana. The Permian remains on their focus; with economic pressure on, there are rich pickings in the shale patch that could turn American shale from a patchwork of ragtag independent drillers to big boy-dominated. In the short-term, that promises quick returns after the panic – especially with ExxonMobil and Chevron declaring net losses of US$1.08 billion and US$8.3 billion for Q2, respectively – but the underlying assumption to that is that the energy industry will recover and continue as it is for the foreseeable future, rather than the major upheaval predicted by their European counterparts.

For shareholders, and the companies themselves, the expectation is what the future will hold once the worse is over. That Q2 2020 financials dismal performance was never in doubt. What is more revealing is where the supermajors will go from here. Will BP’s attempt to end the supermajor era pay off? Or will American optimism return us back to business as usual? It’s two different visions of the future that will either way spell a sea change for the industry.

Market Outlook:

  • Crude price trading range: Brent – US$43-45/b, WTI – US$40-42/b
  • Global crude oil price benchmarks moved higher after a devastating blast in Lebanon that levelled a significant amount of Beirut’s port facilities
  • However, the market is also cautious as OPEC+ begins to wind its supply cuts down to a new level of 7.7 mmb/d with concerns that demand recovery is slower-than expected
  • OPEC’s Gulf nations – Saudi Arabia, Kuwait and the UAE – also ended voluntary cuts made in June, but are looking to force Iraq to 100% compliance in August and September as the latest data continues to show it lagging behind commitments

End of Article 

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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.

August, 07 2020
Suriname’s Mega Discovery

It was just over five years ago that ExxonMobil discovered first oil in Guyana, transforming the sleepy South American country into the world’s upstream hotspot in just half a decade. The strike rate there has been amazing – 18 discoveries out of 20 well campaigns, and more seem to coming as new discovery efforts get underway. This made Guyana the envy of its neighbours. And why not? The Guyanese economy is projected to grow at 86% y-o-y in 2020, despite the Covid-19 pandemic, as first commercial oil from the Liza field hit the market.

Just over the Guyana border, Suriname, a former Dutch colony had all the more reason to be envious. Unlike Guyana, Suriname has an established upstream industry. Managed by the state oil firm Staastsolie, the volumes are paltry: the onshore Calcutta and Tamabredjo field collectively produce at a current rate of 17,000 b/d. Guyana’s Liza field alone is 15 times larger than Suriname’s total crude output. But the Guyanese miracle always did herald some hope that some of that golden dust could blow Suriname’s way, not least because the giant offshore discoveries in the Staebroek block were just across the maritime border.

In January 2020, this bet proved right. US independent Apache announced it had made a ‘significant oil discovery’ at the Maka-Central 1 well, the first suggestion that the Cretaceous oil formation in Guyana extended southeast to Suriname. Two more discoveries were announced by Apache in quick succession, Sapakara West and, just this week, Kwaskwasi. All three are located in the 1.4 million acre offshore Block 58, which was originally held entirely by Apache before French supermajor Total bought into a 50% stake just before the Maka Central discovery was announced. Three discoveries in six month is quite a payoff, especially with the Kwaskwasi-1 well delivering the highest net pay and confirming a ‘world-class hydrocarbon resource’. More importantly, initial findings suggest that Kwaskwasi holds oil with API gravities in the 34-43 degree range, the sort of light oil that is perfect for petrochemicals and higher-grade fuels.

With Total scheduled to take over operatorship of the block after a fourth drilling campaign, the partners are eager to extend their streak. The Sam Croft drillship is scheduled to head to Keskesi, the fourth scheduled prospect in Block 58, after operations at Kwaskwasi-1 have concluded, and an additional exploration campaign is already in the plans for 2021.

Total and Apache aren’t the only ones playing in Surinamese waters, though they are the first to hit the payday. Most of the country’s offshore blocks have been apportioned, snapped up by ExxonMobil, Kosmos, Petronas, Tullow and Equinor, and all are hoping to be the next to announce a find. ExxonMobil, with Equinor and Hess Energy, have a good position in Block 59, just next to the Caieteur block in Guyana, while Kosmos is hunting in Block 42, right next to the Canje block in Guyana. However, it is Malaysia’s Petronas that is the next likely candidate. Present in Suriname since 2016, when it drilled the exploratory Roselle-1 well in Block 52, Petronas also has interests in Block 48 and Block 53, and recently completed a farm-out sale with ExxonMobil for 50% of Block 52. Its drilling campaign for the Sloanea-1 well is scheduled to begin in Q4 2020, and will be keenly watched by all in Suriname.

Unlike Guyana that had no state oil company, Suriname has existing national oil infrastructure. Staatsolie currently controls onshore and shallow water areas in the country. However, all wells drill in offshore Block A, B, C and D have turned out dry so far. That leaves Staatsolie in a situation: its own areas are not prolific as discoveries by Total, Apache, Petronas et al. For now, Staatsolie is looking to gain rights to 10-20% of any oil discovery within Suriname, but the framework for this is weak and it must navigate carefully to not antagonise the oil majors that are powering the discoveries in its waters. It will do well to avoid the confrontational attitude that is jeopardising LNG development in Papua New Guinea with ExxonMobil and Total, but Staatsolie does have a claim to Suriname’s oil riches for itself.

For now, it is exhilarating to observe the progress in this previously quiet corner of South America. It is the closest thing to frontier oil exploration in the 21st century, with each new discovery generating more and more excitement. Who would have thought there was so much oil left undiscovered? Guyana has shot into the spotlight, Suriname is starting its own ascent and… who knows… could French Guiana be next?

End of Article 

Get timely updates about latest developments in oil & gas delivered to your inbox. Join our email list and get your targeted content regularly for free. Click here to join.

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.

August, 01 2020