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The Reality of Digital in Oil & Gas

What does digitization mean for the oil and gas industry?

Digital has been the big buzz word in the industry for some time now – but what exactly does it mean. McKinsey & Company Senior Partner Matt Rogers sat down with the Financial Times US Industry and Energy Editor, Ed Crooks in the first of the Digital Dialogues in Oil & Gas series to discuss the impact of digital in the industry.

Ed Crooks

Ed Crooks

US Industry and Energy Editor

FINANCIAL TIMES

See bio 

Matt Rogers

Matt Rogers

Senior Partner

MCKINSEY & COMPANY

The Financial Times is one of the world’s leading business news organizations, recognized internationally for its authority, integrity, and accuracy. In 2016 the FT passed a significant milestone in its digital transformation as digital and services revenues overtook print revenues for the first time. The FT has a combined paid print and digital circulation of more than 910,000 and makes 60% of revenues from its journalism.

The McKinsey Center for Future Mobility was created to help business leaders and policymakers come to terms with a future that is increasingly autonomous, connected, electrified, and shared. Based in four global hubs (Beijing, Detroit, Munich, and Silicon Valley), our forward-thinking and integrated perspective, industry expertise, proprietary research, and global convening power give us a unique combination of assets to help clients navigate the mobility revolution.

www.mckinsey.com

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

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Our fresh commitment to low carbon

The world is demanding more energy every day to support growth and prosperity. At the same time, it’s demanding energy with fewer emissions. At BP we’re taking on this dual challenge across all of our business activities. We’re growing our business, providing more energy to the world. And at the same time, we’re reducing emissions in our operations, improving our products and creating low carbon businesses. This is how BP is helping the world transition to a low carbon future. As part of this, we are setting some new and important targets. Head to bp.com/energytransition for details.

Published by BP on Apr 16, 2018

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Rethinking the oil and gas organization

December 2016, McKinsey & Company, www.mckinsey.com. Copyright (c) 2018 McKinsey & Company. All rights reserved. Reprinted by permission.

Organizational choices made during a time of resource scarcity need reexamination when the cycle turns.

When business cycles turn, cyclical industries can struggle to retool their organizations for the new environment. For instance, today’s oil and gas companies were developed in a time of resource scarcity. To get at those hard-to-find, difficult-to-develop resources, companies greatly expanded the role of their central functions—mandating them to set common standards, make technical design decisions, track company-wide metrics, and disseminate best practices. This worked well during a decade of high growth and high prices but created complexity that added costs, stifled innovation, and slowed down decision making. As these central teams expanded, general and administrative costs grew fivefold, hitting nearly $5 per barrel in 2014 (exhibit), with the biggest increases coming from technical functions such as engineering, geosciences, and health and safety.

Oil companies have cut support functions since 2014 but must consider more radical organizational changes as prices remain weak.

With prices now below $50 a barrel, that organizational blueprint is no longer sustainable. While companies have cut their support functions since 2014, the overall organizations supported by these functions are also smaller. This suggests further reductions in corporate functions will be needed, as well as new organizational models.

A more agile organization, with fluid teams and looser hierarchies, can lower costs and create greater responsiveness to today’s vastly different markets—ranging from megaprojects to less asset-heavy unconventional shale-oil and renewable-asset plays. Technologies such as networked sensors that generate and share data can help optimize production processes, while digitally enabled automation of routine manual activity can reduce human risk and spur productivity. Critically, the structures built to manage scarce talent and large-scale megaprojects will need to be fundamentally redesigned. We see two models arising: for lower-risk assets such as tight oil, a very lean corporate center with highly autonomous asset teams will suffice, while higher-risk, more capital-intensive assets will need a comparatively stronger center with deeper functional and risk-management capabilities.

For additional insights, see “The oil and gas organization of the future.”

About the author(s)

Christopher Handscomb is a partner in McKinsey’s London office, Scott Sharabura is an associate partner in the Calgary office, and Jannik Woxholth is a consultant in the Oslo office.

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.

ExxonMobil to Join Stanford Strategic Energy Alliance

  • Builds on Global Climate and Energy Project’s 15 years of success
  • Strong science and exploratory research to develop low-carbon energy solutions
  • $20 million commitment in addition to ExxonMobil’s GCEP investment of more than $100 million
  • Expands company’s collaborative work with academic and research institutions around the world

IRVING, Texas–(BUSINESS WIRE)–Exxon Mobil Corporation (NYSE:XOM) today announced that it will become the first founding member of the new Stanford Strategic Energy Alliance, an initiative that will examine ways to improve energy access, security and technology while reducing impacts on the environment. As part of its commitment, ExxonMobil will contribute $20 million in funding over five years to research and develop lower-carbon energy solutions.

The Stanford Strategic Energy Alliance builds on the success of the Global Climate and Energy Project (GCEP), also led by Stanford, which focused exclusively on low-emissions, high-efficiency energy technologies. ExxonMobil has sponsored GCEP since its inception in 2002 with a commitment of $100 million and additional contributions toward specific projects. In its 15 years of work, GCEP has evolved into a pioneering collaboration of scientists, engineers, researchers and students focused on identifying breakthrough low greenhouse gas emission energy technologies that could be developed and deployed on a large scale.

“ExxonMobil has worked with Stanford to advance low-carbon technologies over the last 15 years, and we’re excited to be the first founding member of this new endeavor,” said Bruce March, president of the ExxonMobil Research and Engineering Company. “Identifying scalable solutions for addressing the dual challenge of supplying energy to meet global demand while minimizing the risk of climate change is one of our core missions. We are continuously looking for ways to improve existing supply options and manufacturing processes while managing carbon intensity.”

Since its creation, GCEP has sponsored more than 100 research programs in the United States, Europe, Australia, China and Japan, and has resulted in over 900 papers in leading journals and more than 1,200 presentations at conferences. Building on fundamental science, significant advances have been made in the areas of photovoltaic energy, renewable and lower carbon fossil fuels, batteries and fuel cells. More than 60 technologies have also been developed and 15 patents have been issued. Multiple companies have also started up as a direct result of or inspiration from GCEP research.

The new Stanford Strategic Energy Alliance will pair industry alliance members and Stanford professors who share common research objectives across the spectrum of energy topics from science and engineering to policy and business. Managed by the Stanford Precourt Institute for Energy, the alliance will also fund some early-stage research at the direction of its faculty leadership.

ExxonMobil’s support for the Stanford Strategic Energy Alliance expands the company’s collaborative efforts with other academic and research institutions that are focused on developing an array of new energy technologies, improving energy efficiency and reducing greenhouse gas emissions. The company currently works with about 80 universities in the United States, Europe and Asiato explore next-generation energy technologies, including founding members of MIT Energy InitiativePrinceton E-ffiliates Partnership and University of Texas at Austin Energy Institute.

Source: Exxon Mobil Corporation

ExxonMobil
Media Relations, 972-940-6007

Offshore, oil, gas, drilling

Petroleum Engineers Play an Important Role in Sustainability

Some people balk at the idea that oil and gas has a role to play in a sustainable future, but the reality on the ground suggests otherwise.

“Supplying energy for the world is a monumental task. There continue to be improvements in renewable energy sources; however, reasonable forecasts of growth in renewables suggest fossil fuels will remain the primary source of the world’s energy for decades to come,” Nathan Meehan, president of the Society of Petroleum Engineers, wrote in an article published by SPE in March 2016.

Even with the increasing adoption of renewable energy resources, Meehan notes that fossil fuels still play an important role in meeting today’s energy needs and using them prudently is the best way to make sure that our generation does not compromise the ability of future generations to meet their own needs.

The drive toward renewables is evident in the US where last year nearly half of utility-scale capacity additions on the power grid came from renewable sources like solar and wind, according to the US Energy Information Administration.

But even with the recent gains, renewables only account for a minority of total US power production and their intermittent nature creates the need for energy storage or backup generation that can be brought online quickly – like natural gas fired power plants – to stabilize the grid. The bulk of heavy lifting in the US power generation sector is still done by natural gas (34%), coal (30%) and nuclear (20%), according to EIA data.

This data suggests that fossil fuels will still be needed for decades to come in the power generation sector, and that’s only the tip of the iceberg. A myriad of other industries count on energy and products derived from oil and natural gas.

Considering this, SPE takes seriously the need to extract these resources sustainably.

Though many people may not realize it, there are many things that petroleum engineers can do to help ensure that oil and gas is part of a sustainable energy solution. Meehan says these areas include:

  • Minimizing methane emissions
  • Reducing or eliminating flaring
  • Supporting energy efficiency and conservation
  • Ensuring wellbore integrity
  • Reducing the surface footprint of wells
  • Eliminating spills
  • Optimizing field development and management

SPE offers its members opportunities to train, share knowledge and advance practices to further these goals.

SPE’s efforts supplement work being done by a number of producers, several of which voluntarily release sustainability reports that highlight their unique measures – like Statoil, Shell, and Hess. To learn more about what petroleum engineers can do, visit SPE’s website or read Meehan’s full article on the subject here.

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