The future is now: How oil and gas companies can decarbonize

As the pressure to act on climate change builds, the industry should consider a range of options.

If the world is to come anywhere near to meeting its climate-change goals, the oil and gas (O&G) industry will have to play a big part (Exhibit 1). The industry’s operations account for 9 percent of all human-made greenhouse gas (GHG) emissions. In addition, it produces the fuels that create another 33 percent of global emissions (Exhibit 2).

Several trends are focusing on the minds of industry executives. One is that investors are pushing companies to disclose consistent, comparable, and reliable data. Activist shareholders, for example, are challenging the US- and Europe-based oil majors on their climate policies and emissions-reduction plans.1 Investors are also increasingly conscious of environmental issues. In the five markets examined by the Global Sustainable Investment Alliance—Australia and New Zealand, Canada, Europe, Japan, and the United States—sustainable investments reached assets of $30.7 trillion in early 2018, one-third of total investment. At September’s UN climate summit, an alliance of the world’s largest pension funds and insurers (representing $2.4 trillion in assets) committed itself to transition its portfolios to net-zero emissions by 2050.2

At the same time, renewable technologies have been getting cheaper. In the United States, the cost of solar—both photovoltaics (PV) and utility-scale—has fallen more than 70 percent since 2011, and the cost of wind by almost two-thirds. By 2025, they could be competitive with natural gas-based power generation in many more regions.

Other forces are also coming into play. Although there is still no global market, carbon taxes or trading systems cover 20 percent of worldwide emissions, compared with 15 percent in 2017, according to the World Bank.3 Many European governments plan to implement binding GHG emissions targets and are drawing up national energy and climate plans.

Options for the oil and gas sector

To play its part in mitigating climate change to the degree required, the oil and gas sector must reduce its emissions by at least 3.4 gigatons of carbon dioxide equivalent (GtCO2e) a year by 2050, compared with “business as usual” (currently planned policies or technologies)—a 90 percent reduction in current emissions. Reaching this target would clearly be easier if the use of oil and gas declined. But even if demand doesn’t fall much, the sector can abate the majority of its emissions, at an average cost of less than $50 per ton of carbon dioxide equivalent (tCO2e), by prioritizing the most cost-effective interventions. Process changes and minor adjustments that help companies reduce their energy consumption will promote the least expensive abatement options.

The specific initiatives a company chooses to reduce its emissions will depend on factors such as its geography, asset mix (offshore versus onshore, gas versus oil, upstream versus downstream), and local policies and practices (regulations, carbon pricing, the availability of renewables, and the central grid’s reliability and proximity). Already, many companies have adopted techniques that can substantially decarbonize operations—for example, improved maintenance routines to reduce intermittent flaring and vapor-recovery units to reduce methane leaks (Exhibit 3). Cutting emissions is not necessarily expensive. An onshore operator found that about 40 percent of the initiatives it identified had a positive net present value (NPV) at current prices and an additional 30 percent if it imposed an internal carbon price of $40/tCO2e on its operations.

One option is to implement initiatives that offset emissions by tapping into natural carbon sinks, including oceans, plants, forests, and soil; these remove GHGs from the atmosphere and reduce their concentration in the air. Plants and trees sequester around 2.4 billion tons of CO2 a year.4 The Italian energy giant ENI has announced programs to plant 20 million acres (four times the size of Wales) of forest in Africa to serve as a carbon sink. Other companies are looking at how to fund these offset programs; Shell offers Dutch consumers the possibility of paying to offset emissions from retail fuel. The cost of carbon sinks is uncertain; estimates range from $6 to $120 per tCO2e in 2030, depending on the source and the sequestration target.

Any company can invest in offsets. On the whole, however, upstream and downstream operators have different sets of options at their disposal.

What upstream operators can do

Upstream operations account for two-thirds of sector-specific emissions. Below, we discuss some ways in which oil and gas companies are taking action. The economics will vary greatly, depending on the option and local conditions.

Changing power sources. One oil and gas company is using on-site renewable-power generation to provide a cost-effective alternative to diesel fuel. By replacing generators with a solar PV and battery setup, the company not only reduced emissions significantly but also broke even on its investment in five years. Connecting onshore or nearshore rigs and platforms to the central grid (as opposed to decentralized diesel generation) can also work well: for example, in its drive for electrification, Equinor recently connected its Johan Sverdrup field, which lies 140 kilometers offshore, to the grid. If upstream producers electrified most of their operations, that could add up to 720 tCO2e a year in abatement by 2050, at an estimated cost of $10/tCO2e, depending on local electricity costs.

Reducing fugitive emissions. Companies can cut emissions of methane, a powerful GHG, by improving leak detection and repair (LDAR), installing vapor-recovery units (VRU), or applying the best available technology (such as double mechanical seals on pumps, dry gas seals on compressors, and carbon packing ring sets on valve stems).5 One company replaced the seals in pressure-safety valves, which had been found to be a frequent source of leaks, and then was able to monetize these streams of saved or captured gas. We estimate that reducing fugitive emissions and flaring could contribute 1.5 GtCO2e in annual abatement by 2050, at a cost of less than $15/tCO2e.

Electrifying equipment. One company replaced gas boilers with electric steam-production systems, including high-pressure storage for nighttime steam supply, to support separation units. The project will pay for itself in less than ten years. In many circumstances, there is already a good business case, on purely financial grounds, for combining the use of solar and gas in place of conventional boilers.

Reducing nonroutine flaring through improved reliability. One operator found that 70 percent of all flaring emissions came from nonroutine flaring, mainly as a result of poor reliability. It, therefore, focused on improving its operations—for example, by carrying out predictive maintenance and replacing equipment. These actions not only reduce emissions but also raised production. Best-in-class operators are making significant strides in reliability thanks to area-based maintenance and multiskilling. Predictive analytics can reduce the frequency of outages to compressors or other equipment.

Reducing routine flaring through improved additional gas processing and infrastructure. While some flaring may be unavoidable, the capacity constraints of infrastructure can lead to more than either companies or the public might want. In the Permian Basin, for example, a record of 661 million cubic feet a day (mcf/d) was flared in the first quarter of 2019. Addressing this challenge requires additional gas-processing facilities, as well as gathering and transport infrastructure. The Gulf Coast Express natural-gas pipeline, which went operational in September, will help. An additional 16 billion cubic feet a day (bcf/d) of planned capacity increases on pipelines from the Permian to the Gulf Coast is now under discussion.

Increasing carbon capture, use, and storage (CCUS). While this technology is projected to play only a minor role in the sector’s overall decarbonization, O&G players can still significantly influence its adoption and development. There are 19 large-scale CCUS facilities in commercial operation; four more are under construction and another 28 in development. There are also a number of demonstration and pilot projects. Together, plants under construction and in operation can capture and store about 40 MtCO2e a year. Total CCUS capacity could increase by as much as 200 times by 2050. In this market, the oil industry is well placed to lead because it already uses carbon captured via CCUS for use in enhanced oil recovery (EOR). That oil is also less emissions-intensive than the conventionally extracted variety.

A number of countries are looking to accelerate CCUS development. In 2018, for example, the US Congress passed a provision (45Q) increasing the tax credit that power plants and industries can take for either storing or using captured carbon. Congress is considering a bill, known as USE IT, to support the construction of CCUS facilities and CO2 pipelines and to finance research on direct-air capture. The business case for CCUS works only under specific economic conditions, such as tax relief or the imposition of a carbon price. Without some kind of regulatory framework, CCUS does not create value in and of itself.

CCUS costs $20/tCO2e for selected processes in the oil and gas sector but as much as $100 to $200/tCO2e in other industries, such as cement. One undertaking to watch is the Clean Gas Project in northern England, where a consortium of six oil and gas companies is building what could be the first commercial natural-gas plant with full CCUS capacity.

Rebalancing portfolios. Operators are starting to take a close look at their upstream portfolio choices. The highest-emitting reservoirs are nearly three times more emissions-intensive than the lowest. For example, complex reservoirs—highly viscous, in deep or ultradeep water, compartmentalized, or high pressure and temperature—may be at a structural emissions disadvantage. They may, therefore, become increasingly unattractive to develop in the future.

What downstream operators can do

Downstream operators are exploring many of the same ideas, such as energy efficiency and the electrification of low- to medium-temperature heat and energy. But they have distinctive options as well.

Energy efficiency. Efficiency is a factor in every part of the industry, of course, but new downstream-specific technologies can make a big difference. Waste-heat-recovery technology and medium-temperature heat pumps in refineries, for example, reduce the amount of primary energy used in distillation. One company saved €15 million in capital expenditures by forecasting its required steam usage hour by hour and incorporating this into a thermodynamic model to determine the required specifications for replacement equipment.

Green hydrogen. Hydrogen production through electrolysis has become both more technically advanced and less expensive. Bloomberg New Energy Finance estimates that the cost of hydrogen could drop as much as two-thirds by 2050. Using renewable energy rather than steam methane reforming (SMR) to power the electrolysis could offer refineries a way to reduce emissions—a result known as “green hydrogen.” An alternative, “blue hydrogen,” uses SMR plus CCUS. The attractiveness of the different technologies depends on the local economies—in particular, the availability of cheap storage capacity for CCUS or cheap renewable electricity.

Green hydrogen is not a speculative technology in oil and gas. Shell and ITM Power, a UK-based energy-storage and clean-fuel company are building the world’s largest hydrogen electrolysis plant at a German refinery, with support from the European Union. Revenue will come from selling hydrogen to the refinery, which will use it for processing and upgrading its products and for grid-balancing payments to the German transmission system. That business model justifies the installation.6

High-temperature electric cracking. In refining, several pilot projects use electric coils (instead of fuel gas) to provide heat. The technology is still at an early stage and small in scale. Moreover, the economics are sensitive to the price of electricity compared with gas and to the options for selling the fuel gas. Those economics improve if the investment is coordinated with the natural investment cycle to support additional capital expenditures—and, of course, if power can be purchased or generated under favorable financial terms.

Greener feedstocks. Replacing some conventional-oil feedstocks in refineries with biobased feedstocks or recycled-plastic materials (initially, through pyrolysis or gasification) would also reduce emissions—not only Scope 1 but also, to a large extent, Scope 3 emissions. In an increasingly decarbonizing world, this may extend the lifetime of refining assets.


The oil and gas sector will play an important role in the global energy transition; how it will face that future is a matter of strategy. As transparency increases, so may expectations. Customers, employees, and investors are already starting to distinguish the leaders from the laggards. Oil and gas companies that get ahead of the curve could find themselves better positioned for change.

This article is part of a series on energy transition and decarbonization.

About the author(s)

Chantal Beck is a partner in McKinsey’s London office; Sahar Rashidbeigi is a consultant in Amsterdam, where Occo Roelofsen is a senior partner and Eveline Speelman is an associate partner.

We strive to provide individuals with disabilities equal access to our website. If you would like information about this content we will be happy to work with you. Please email us at McKinsey_Website_Accessibility@mckinsey.com

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Shell is a passionate supporter of science, technology, engineering and mathematics (STEM) education. The skills of scientists, engineers, educators and leaders are essential to meeting the world’s demand for energy, whilst reducing carbon emissions. Our vision is to help equip future generations of problem-solvers, leaders and innovators to tackle the energy challenges that face us all. #makethefuture To find out more about STEM and the education programmes Shell support globally please visit http://www.shell.com/education Transcript: http://www.shell.com/content/dam/roya…

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Emissions Monitoring Innovation – Clair

Satellite measurement is an ideal method for monitoring methane emissions from shale gas operations. Current methods require crews to visit each facility on a regular basis, whereas GHGSat’s high resolution satellites can identify superemitters through periodic surveys of all shale gas operations, without any on-site equipment, at a fraction of the cost of current methods.

As of 2019, GHGSat aircraft measurements will provide very-high resolution measurements of shale gas plays to complement GHGSat satellite measurements. Very high resolution measurements from GHGSat aircraft sensors will enable detection of smaller leaks, and localize those leaks within a facility to facilitate repair. GHGSat aircraft sensors will leverage the same post-processing toolchain used by its satellites, thereby cross-validating results and providing cost-effective aircraft services.

GHGSat’s “tiered solution” will combine satellite and aircraft measurements in a single service to detect approximately 90% of all methane leaks (by volume) from shale gas operations. This service is unique – no other company can combine both satellite and aircraft measurements in a single, cost-effective service for shale gas operators.

http://www.ghgsat.com/

 

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Climate Alarmists May Inherit the Wind

They likened a courtroom ‘tutorial’ to the Scopes Monkey Trial. But their side got schooled.

San Francisco

Five American oil companies find themselves in a San Francisco courtroom. California v. Chevron is a civil action brought by the city attorneys of San Francisco and Oakland, who accuse the defendants of creating a “public nuisance” by contributing to climate change and of conspiring to cover it up so they could continue to profit.

No trial date has been set, but on March 21 the litigants gathered for a “climate change tutorial” ordered by Judge William Alsup —a prospect that thrilled climate-change alarmists. Excited spectators gathered outside the courtroom at 6 a.m., urged on by advocates such as the website Grist, which declared “Buckle up, polluters! You’re in for it now,” and likened the proceeding to the 1925 Scopes Monkey Trial.

In the event, the hearing did not go well for the plaintiffs—and not for lack of legal talent. Steve W. Berman, who represented the cities, is a star trial lawyer who has made a career and a fortune suing corporations for large settlements, including the $200 billion-plus tobacco settlement in 1998.

“Until now, fossil fuel companies have been able to talk about climate science in political and media arenas where there is far less accountability to the truth,” Michael Burger of the Sabin Center for Climate Change Law at Columbia University told Grist. The hearing did mark a shift toward accountability—but perhaps not in the way activists would have liked.

Judge Alsup started quietly. He flattered the plaintiffs’ first witness, Oxford physicist Myles Allen, by calling him a “genius,” but he also reprimanded Mr. Allen for using a misleading illustration to represent carbon dioxide in the atmosphere and a graph ostensibly about temperature rise that did not actually show rising temperatures.

Then the pointed questions began. Gary Griggs, an oceanographer at the University of California, Santa Cruz, struggled with the judge’s simple query: “What do you think caused the last Ice Age?”

The professor talked at length about a wobble in the earth’s orbit and went on to describe a period “before there were humans on the planet,” which “we call hothouse Earth.” That was when “all the ice melted. We had fossils of palm trees and alligators in the Arctic,” Mr. Griggs told the court. He added that at one time the sea level was 20 to 30 feet higher than today.

Mr. Griggs then recounted “a period called ‘snow ballers,’ ” when scientists “think the entire Earth was frozen due to changes in things like methane released from the ocean.”

Bear in mind these accounts of two apocalyptic climate events that occurred naturally came from a witness for plaintiffs looking to prove American oil companies are responsible for small changes in present-day climate.

The defendants’ lawyer, Theodore J. Boutrous Jr. , emphasized the little-discussed but huge uncertainties in reports from the United Nations Intergovernmental Panel on Climate Change and the failure of worst-case climate models to pan out in reality. Or as Judge Alsup put it: “Instead of doom and gloom, it’s just gloom.”

Mr. Boutrous also noted that the city of San Francisco—in court claiming that rising sea levels imperil its future—recently issued a 20-year bond, whose prospectus asserted the city was “unable to predict whether sea level rise or other impacts of climate change or flooding from a major storm will occur.”

Judge Alsup was particularly scathing about the conspiracy claim. The plaintiffs alleged that the oil companies were in possession of “smoking gun” documents that would prove their liability; Mr. Boutrous said this was simply an internal summary of the publicly available 1995 IPCC report.

The judge said he read the lawsuit’s allegations to mean “that there was a conspiratorial document within the defendants about how they knew good and well that global warming was right around the corner. And I said: ‘OK, that’s going to be a big thing. I want to see it.’ Well, it turned out it wasn’t quite that. What it was, was a slide show that somebody had gone to the IPCC and was reporting on what the IPCC had reported, and that was it. Nothing more. So they were on notice of what in IPCC said from that document, but it’s hard to say that they were secretly aware. By that point they knew. Everybody knew everything in the IPCC,” he stated.

Judge Alsup then turned to Mr. Berman: “If you want to respond, I’ll let you respond. . . . Anything you want to say?”

“No,” said the counsel to the plaintiffs. Whereupon Judge Alsup adjourned the proceedings.

Until now, environmentalists and friendly academics have found a receptive audience in journalists and politicians who don’t understand science and are happy to defer to experts. Perhaps this is why the plaintiffs seemed so ill-prepared for their first court outings with tough questions from an informed and inquisitive judge.

Activists have long claimed they want their day in court so that the truth can be revealed. Given last week’s poor performance, they may be the ones who inherit the wind.

Mr. McAleer is a journalist, playwright and filmmaker. He is currently writing a play about Chevron Corp.’s legal fight over alleged pollution in Ecuador.

Re-Published from THE WALL STREET JOURNAL

https://www.wsj.com/articles/climate-alarmists-may-inherit-the-wind-1522605526

 

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McKinsey: Operating models for oil and gas fields of the future

As the global energy transition accelerates, upstream operators must modernize and shift to more economic operating models. Where and how should they seek the next generation of efficiency gains?

As predictions of an early peak in oil demand take hold, upstream operators must find ways to produce more energy, more efficiently. Many have made significant performance gains in recent years. Across the sector, production costs are down 30 percent; safety incident frequency has fallen by a third, and production losses have declined by 15 percent since 2014. Yet more is necessary.

A marked spread in performance remains between the bottom and top quartile operators in every basin. On the UK Continental Shelf (UKCS), for instance, over 40 percentage points separate the lowest production efficiency asset from the top quartile. Similarly, the highest cost asset on the UKCS has twice the unit operating cost as the median and four times that of the top quartile in the basin.1

Furthermore, new technologies and ways of working are resetting top quartile performance levels. Our research2shows digital technologies may improve total cash flows by USD 11 per barrel across the offshore oil and gas value chain, adding USD 300 billion a year by 2025.

What distinguishes the success cases from the also-rans? What sustains their improvement momentum? Through our extensive experience of leading asset turnarounds in Petroleum Asset eXcellence, we observe that upstream operators who sustain their improvement momentum do two things well.

First, they challenge five interlinked drivers of their operating model in an integrated way (Exhibit 1). These drivers are: their asset strategy; physical equipment-in-place; work required to operate and maintain that equipment; workflows and methods used to conduct that work; and the competencies required from the team deployed to do it. While each driver will yield some efficiency gains when used alone, in aggregate, they can more than double the value potential of existing operations.

Second, having had one go at improving their operating model, these operators are willing to build on what did not work in round one, and take a second, third, or even fourth look. In fact, they build a continually evolving operating model that achieves higher and more predictable production performance, operating costs for a ‘lower forever’ price environment, and smaller, flexible and more diverse teams that are better suited to the industry’s aging pool of skilled labor.

Exhibit 1
What do successful operators do well?

This article lays out a concrete logic that any operator might use to develop a continually evolving operating model and illustrates through real examples the success factors of making this change happen.

Developing a clean-slate vision of your operating model

In early 2015, an operator with upstream assets in various life stages found itself with negative cash flows, declining production and escalating costs. A vertiginous price drop and unconvincing track record of operational performance made any prospect of recovery seem unlikely. The operator went back to a clean slate: it took a hard look at its field and hub strategies—reprioritizing its efforts across near-field exploration, wells-reservoirs-facilities management and asset rejuvenation; made radical choices to optimize lifting costs and staffing levels; and pursued capital productivity relentlessly across its portfolio. Over the next year, as the operator’s competitiveness improved, its confidence rose as well.

It took another look at its operating model, replicating this end-to-end clean-slate approach, and emerged with an ambitious agenda to restore positive cash flows within two years. Since then, this operator has divested non-core assets, rezoned unwanted surplus capacity on declining assets, improved front-line agility, and embraced digital technologies. With a continually evolving operating model, it has reverted to positive cash flows a year earlier than planned, marking a first in its recent history.

How did the operator build a clean-slate vision of its operating model? What logic does it apply every year? Exhibit 2 highlights the five interlinked drivers of operating model redesign and provides a checklist of questions any operator might ask itself.

Exhibit 2

Leading upstream operators maintain a coninually evolving operating model.

1. How does your asset strategy fit with your asset’s life stage?

Exploration and production (E&P) companies rarely look at asset strategies in operational excellence programs. This is a missed opportunity. Clean-slate asset strategies help operators make deliberate choices on which fields to grow, operate as mature, swap with others, abandon, or divest. A Western European operator with mature operations realized that half the fields in its portfolio would generate 95 percent of its future cash flows. Consolidating the portfolio would free up scarce capital and talent for its most productive assets with material remaining reserves. Moreover, legacy ownership structures concealed bottlenecks in third-party infrastructure: this restricted current operating capacity and the ability to mature reserves through production. Redrawing portfolios in line with which operator-controlled critical processing capacity and evacuation routes—swapping assets and acreage with contiguous operators, for instance—could improve the basin’s future economics and simplify day-to-day operations for individual parties.

A regular discipline of considering clean-slate asset strategies—commonly in an annual cycle—helps revisit field development plans and improve recovery rates. An African client with a portfolio of 800 closed-in wells concluded that intervening in a mere 5 percent of the closed-in well stock could add 30 kboe/d in the first year, with payback also within the same period. It made wells and reservoir management a top priority in capital allocation and operational plans across its upstream portfolio.3

Would you like to learn more about Petroleum Asset eXcellence (PAX)?

More than all else, clean-slate asset strategies enable customization of our remaining four drivers based on whether an asset is going through growth or decline. Operators committed to building and maintaining additional capacity, such as capital-intensive facilities improvement programs, only where there are remaining reserves and future value potential, or they eliminate expensive optionality wherever the asset’s maturity makes it irrelevant to future value creation.

2. What is the leanest physical footprint for your asset?

The physical footprint of an asset has always been a major driver of project economics. With increasingly small and stranded reserves and limited discretionary spending, it has become the single largest factor in project break-evens. Additionally, the physical footprint shapes operational processes and determines the structural limits of operating cost optimization across asset lifecycles. Examples of these limits include deck space, number, and type of crane, storage and layout, and redundancy in installed equipment. We recommend that operators consider the total value of owning their physical footprint—in design and in operations.

For new builds, considering the total value of owning their physical footprint may lead to smaller, modular, unmanned or energy self-sufficient designs. A North Sea independent used a standard platform design to shorten the engineering process and achieve first gas within 18 months versus industry averages of 30 to 36 months. The standard topsides—developed for two marginal fields were usable in other fields within a comparable range of gas throughput. The modular jacket was suitable for similar shallow water resources. Solar and wind power generation with battery storage reduced air emissions and offered energy self-sufficiency. Standardization and modularity rationalized maintenance costs just as much as FEED capital. As routines were replicable across the portfolio, a standard campaign-based maintenance approach yielded material synergies in engineering, work preparation, and spares management.

For mature assets, standard subsea design and equipment improves the economic attractiveness of brownfield expansions. Besides, obsolescence, fatigue or corrosion issues can all serve as triggers to make the asset easier and more economical to maintain. One operator in West Africa replaced traditional flowlines with thermoplastic ones. With better corrosion resistance, higher asset integrity and longer life, these new materials drastically extended schedules for inspections and maintenance routines. In a different example, a North Sea late-life asset systematically challenged the equipment in place to reduce surplus capacity in power generation, compression, and storage vessels. The lower physical footprint eliminated 25 percent of required maintenance hours and allowed redeployment of the maintenance team to more pressing pre-Cessation-of-Production imperatives. With a total value of ownership approach, this operator tackled the growing divergence of needs from means in its initial operating envelopes, and structurally reduced its operating cost base.

3. How can you compress your workload?

In asset turnarounds, we commonly encounter over-reliance on time-driven maintenance philosophies. Equipment strategies are set to standard specifications and adapted marginally as assets move through steady-state production into decline. The outcome is inflated workloads and costs, combined with an operations and maintenance plan that does not adapt adequately to emerging reliability or integrity challenges. Our proprietary maintenance benchmarks indicate that there can be a 5 to 10 percentage point differential in production efficiency and 20 to 30 percentage point differential in maintenance costs between top quartile operators and the also-rans.

Success cases exercise both traditional and digital levers to optimize the overall operations and maintenance workload. Traditional choices include stepping away from a 100 percent inspection approach to risk-based strategies in mid-life assets or run-to-failure for late life ones. However, next-generation operations and maintenance is centred on equipment sensors for performance data, advanced analytics and machine learning to predict and avoid failures, with maintenance or replacement on an as-needed basis. This end-to-end digitally enabled system makes activity workloads smaller and more predictable, feeds into more efficient and economic management of materials and people, and levels the operational risk-return profile of an oil and gas business towards the steadier profile of a manufacturing one.

A mature asset operator makes timely interventions through failure prediction to reduce asset downtime. Predictive maintenance incorporates sensor data and condition monitoring results in a machine-learning algorithm, which recognizes patterns associated with different failure modes on a specific machine. As no two machines are alike, the learning algorithm can customize trigger points for failures on each individual piece of equipment, thus allowing maintenance teams to plan better, reduce the incidence and severity of failures, and compress the time to recovery. The operator has reduced downtime on critical machines by as much as 30 to 50 percent.

Most significantly, predictive techniques are redefining the scope and composition of maintenance activities, enabling organizations to have smaller maintenance teams and lower operating costs. Exhibit 3 shows the expected future impact for this mature asset operator.

Exhibit 3

Illustrative example – a full scale-up is expected to transform maintenance scope, efficiency and costs

Predictive techniques are relevant regardless of the life stage of an asset. However, operators may choose to match upfront investment with the remaining life of their assets. While an overhaul of multiple systems into a single platform may have a positive business case at an early-life asset, a mature asset may better use an integrated platform that consolidates scattered data from legacy systems and rapidly digitizes key operational workflows.

4. How can you multiply the work hours you obtain?

Upstream operators consistently appear middle of the pack in time-in-motion studies, reporting an average of 20 to 30 percent of a shift as productive. However, world-class process-based industries and leading upstream operators can extract 7 hours of value-added work in a 12-hour shift; in some cases, particularly in campaign-based interventions, they can achieve 8 to 10 hours of useful work per shift.

Lean tools continue to be the mainstay of improving productivity. In addition, the vision for next-generation operations and maintenance is to put the employee at the core, flipping the model from ‘thinking like the manager’ to ‘thinking like the technician.’ This means that anything in the way of the technician’s doing value-added work must be minimized, or where possible, automated.

At an offshore asset, we shadowed technicians to uncover their pain points. Three pain points emerged at the top:

  • A manual and substantial data reporting burden that went beyond industry compliance requirements: this trapped the offshore installation manager and supervisors at their desktops.

  • A time-based schedule and planned loading approach in compliance with company maintenance execution standards: often, this imposed twice as many work orders and doubled the time per work order relative to actual execution data. While the asset was plan compliant, the maintenance teams had effective surplus capacity.

  • Focus on a process rather than equipment or systems: this prompted compliance with complex process steps and reporting to relevant technical authorities over equipment care and ownership.

Addressing technician pain points along the maintenance execution process was the main lever for improving productivity. The operator reacted with three innovations:

  • Digitization of key workflows had the secondary benefit of allowing most compliance data to be tracked autonomously and routed to a secure site for reporting to the parent company or regulator. This freed up offshore supervision capacity. Gradual deployment of IoT and mobile devices over the next two years was expected to provide further relief through real-time reporting.

  • Time-based scheduling and plan loading was replaced with the use of actual execution data captured in digital work tracking systems. Surplus capacity in maintenance teams could be redeployed to liquidate maintenance backlogs or better utilized for standby work. The operator was beginning to implement next-generation control of work, with increased automation in integrated planning, permit-to-work processing, and work notifications.

  • Process simplification liberated front-line time and capacity. Simple engineering was delegated to an offshore engineer who supervised ‘find and fix’ and accelerated simple jobs without routing them back to a central team or contractor.

  • But front-line equipment care and ownership required organizational refinements. This brings us to the fifth driver of next-generation operating models.

Oil-gas-1536x1536-500_Standard

Rethinking the oil and gas organization Read the article

5. What is the minimum organization you need to achieve your business goals?

Upstream companies typically start and end reorganizations with the organization itself. Notwithstanding its limited impact on resourcing levels, this approach constrains companies’ abilities to visualize how they might adopt new technologies, such as digital tools, or introduce organizational agility, a premium functionality in our world of relentless change.4

Building a next-generation operations and maintenance team begins with drafting the minimum capabilities required for steady-state operations. At its most elemental, an operator takes a zero-based budgeting approach: desktop analyses and cross-functional scrums help set the size and shape of the smallest team with the skills to conduct the asset’s baseload activity set, and add incremental capacity only if there is a strong business case for it. So, while an early-life asset operator might aim for equipment familiarity through hands-on commissioning, a late-life asset operator would accommodate capacity to address integrity challenges. Even with this minimalist mindset, it is easy to rationalize why additional technicians should be on standby for unanticipated trips.

We have seen assets operating with teams less than half the prevailing norm, and specific activities, such as routine well interventions for reservoir data acquisition, run with team sizes of around 25 percent of what is typical. Three choices facilitate flexible access to the required capabilities:

  • Fluid teaming. Multiskilling through a second service role, combined operations and maintenance roles or a secondary competence is more talked of than implemented. Many technicians often have broader competences than trades-based staffing models allow. In next-generation operations and maintenance teams, we go further towards an agile organizational structure, designed around equipment ownership. For instance, an equipment improvement team is cross-functional with representation from challenge areas, such as engineering, maintenance or supply chain. It is self-managing and has end-to-end accountability for the reliability of its equipment. Each team sets out with a performance target associated with its equipment and has compensation tied to the results achieved.

  • Redefining skill requirements. As operators increasingly deploy digital technologies—improving work-scope predictability—unmanned operations become more feasible. An integrated remote operations centre staffed with data scientists and operations-skilled digital translators—who marshal advanced analytics models for production optimisation—is no longer inconceivable.

  • Use of innovative partnerships for non-core and peak load activities. Contracting is the traditional option for flexible access to skills. In a 21st-century organization, this might look more like a risk-sharing partnership. In a recent example, a large upstream oil and gas company established a long-term contract with two asset management contractors to increase production in a mature field. While reserves continued to be owned by the upstream company, the contractors operated under a cost recovery model with a bonus for how quickly they increased unit cash flows. Tailored alliances across the sector, with distinct contributions from participating upstream companies, can go beyond supply chain relationships. A recent merger of two operators combined the operational excellence of a leaner independent with a larger incumbent’s superior basin expertise. In the year following the transaction, the new entity nearly doubled production, providing greater financial robustness and a platform for long-term growth to both partners.

Ultimately, reorganizations must ensure access to the right talent within the asset’s business context. Organizational agility can achieve this without compromising process and personnel safety. Even with fluid teaming, the roles of the offshore installation manager or the site supervisor as safety custodian remain intact.


Achieving a continually evolving operating model will require new approaches to operational transformations, skill sets, and ways of working among the people who will make it happen. While the traditional transformation roadmap to arrive at well-defined goals is still relevant, an agile development and implementation process will be needed to accommodate greater collaboration and learning on the go. Multifunctional teams will work together on end-to-end processes to create new solutions, using shorter sprints to design minimum viable products, and being happy to fail fast as long as they learn in the process. This will put front-line teams and middle management at the heart of the transformation. And operators will have to invest in building both their belief in the value potential and their capability to deliver the required changes.

None of this will be easy, but it will be necessary if oil and gas operators are to attain the next wave of structural improvements amid the uncertainties of an ever-evolving industry.

December 2017, McKinsey & Company, www.mckinsey.com. Copyright (c) 2018 McKinsey & Company. All rights reserved. Reprinted by permission.

The Oil & Gas Technology Centre has invested in three robotics projects to transform pressure vessel inspection

  • Robotics projects announced with both Sonomatic and University of Strathclyde
  • Technologies focus on reducing cost and improving safety of vessel inspection
  • Next Asset Integrity ‘Call for Ideas’ seeks corrosion under insulation solutions

The Oil & Gas Technology Centre has invested in three robotics projects to transform pressure vessel inspection, which costs the industry hundreds of millions each year and poses significant safety challenges.

The projects were selected as part of our first Asset Integrity ‘Call for Ideas’, which launched in 2017. Pressure vessel inspection was identified by the industry as a crucial challenge to maximising economic recovery from the UK Continental Shelf.

Non-intrusive inspection (NII) of pressure vessels can deliver significant cost and safety benefits. Sonomatic’s aim is to develop the next generation of robotic NII technology, with improved speed, agility and autonomy compared with existing systems. The robot, incorporating advanced inspection technologies, will help increase production uptime, reduce costs and improve efficiency.

Separately, we’re working with the University of Strathclyde to develop a new robot crawler equipped with 3D laser scanning and non-destructive testing technology. Existing crawlers are typically deployed only when there is clear line-of-sight for the operator. The University’s solution will construct a virtual, dynamic 3D representation of the inspection site meaning it can be operated safely from a remote location.

We’re also supporting the University of Strathclyde in the use of swarms of small unmanned aerial vehicles, or drones, for visual inspection offshore. Drone swarms, which are being rapidly adopted by the military and for logistics activities, could deliver a safe, flexible and cost-effective alternative to human inspection.

In March 2018, we launch our second Asset Integrity Call for Ideas, focused on predicting, preventing, detecting and repairing corrosion under insulation. More information will be communicated in the coming weeks.

Rebecca Allison, Asset Integrity Solution Centre Manager, said:

“From day one, developing and deploying new technology for pressure vessel inspection has been a key focus area for the Oil & Gas Technology Centre. We’re delighted to be investing in robotics projects with Sonomatic and the University of Strathclyde, which we believe can significantly reduce costs, improve efficiency and enhance safety.

“Process vessel inspection and corrosion under insulation cost the industry more than £300 million each year so it is important that our first two Calls for Ideas focus on these challenges. We’re always looking for innovative ideas and concepts from inside and outside the oil and gas industry and look forward to launching our next Call in March.”

Mark Stone, Integrity Services Manager, Sonomatic, said:

“We’re excited to be working with the Oil & Gas Technology Centre to develop the next generation of robotic inspection tools for non-intrusive inspection. There have been significant advances in robotics technology, inspection solutions and data science over the past few years and the support from the Technology Centre will ensure these are soon available in a practical tool for field application.”

Willie Reid, Director of the Strathclyde Oil and Gas Institute, said:

“The robotics team at Strathclyde, led by Dr Gordon Dobie and Dr Erfu Yang, are excited to be working with the Oil & Gas Technology Centre on these challenges for improving inspection for offshore asset integrity.

“In a multi-disciplinary approach, they will use the broad experience of both the Centre for Ultrasonic Engineering and also the Department of Design, Manufacture and Engineering Management. We will also utilise our experience in transferring technology from other sectors into oil and gas.”

http://www.theogtc.com

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