Halliburton forms strategic agreement with Microsoft and Accenture to advance digital capabilities

HOUSTON – July 17, 2020  Halliburton (NYSE: HAL), Microsoft Corp. (Nasdaq: MSFT) and Accenture (NYSE: ACN) today announced they have entered into a five-year strategic agreement to advance Halliburton’s digital capabilities in Microsoft Azure.

Under the agreement, Halliburton will complete its move to cloud-based digital platforms and strengthen its customer offerings by:

  • Enhancing real-time platforms for expanded remote operations,

  • Improving analytics capability with the Halliburton Data Lake utilizing machine learning and artificial intelligence, and

  • Accelerating the deployment of new technology and applications, including SOC2 compliance for Halliburton’s overall system reliability and security.

Halliburton logo“The strategic agreement with Microsoft and Accenture is an important step in our adoption of new technology and applications to enhance our digital capabilities, drive additional business agility and reduce capital expenditures,” said Jeff Miller, Halliburton chairman, president & CEO. “We are excited about the benefits our customers and employees will realize through this agreement, and the opportunity to further leverage our open architecture approach to software delivery.”

“Moving to the cloud allows companies to create market-shaping customer offerings and drive tangible business outcomes,” said Judson Althoff, executive vice president, Microsoft’s Worldwide Commercial Business. “Through this alliance with Halliburton and Accenture, we will apply the power of the cloud to unlock digital capabilities that deliver benefits for Halliburton and its customers.”

Accenture logoThe agreement also enables the migration of all Halliburton physical data centers to Azure, which delivers enterprise-grade cloud services at global scale and offers sustainability benefits. Accenture will work closely with Microsoft, in conjunction with their Avanade joint venture, to help transition Halliburton’s digital capabilities and business-critical applications to Azure. Accenture will leverage its comprehensive cloud migration framework, which brings industrialized capabilities together with exclusive tools, methods, and automation to accelerate Halliburton’s data center migration and provide for additional transformation opportunities.

“Building a digital core and scaling it quickly across a business is only possible with a strong foundation in the cloud,” said Julie Sweet, chief executive officer, Accenture. “Halliburton recognizes that this essential foundation will provide the innovation, efficiency and talent advantages to do things differently and fast. We are proud to be part of driving this transformational change, which builds on our long history of working with Halliburton and Microsoft.”

The companies expect to complete the staged migration by 2022.

About Microsoft

Microsoft (Nasdaq “MSFT” @microsoft) enables digital transformation for the era of an intelligent cloud and an intelligent edge. Its mission is to empower every person and every organization on the planet to achieve more.

About Halliburton

Founded in 1919, Halliburton is one of the world’s largest providers of products and services to the energy industry. With approximately 50,000 employees, representing 140 nationalities in more than 80 countries, the company helps its customers maximize value throughout the lifecycle of the reservoir – from locating hydrocarbons and managing geological data, to drilling and formation evaluation, well construction and completion, and optimizing production throughout the life of the asset. Visit the company’s website at www.halliburton.com. Connect with Halliburton on FacebookTwitterLinkedInInstagram and YouTube.

About Accenture

Accenture is a leading global professional services company, providing a broad range of services in strategy and consulting, interactive, technology and operations, with digital capabilities across all of these services. We combine unmatched experience and specialized capabilities across more than 40 industries — powered by the world’s largest network of Advanced Technology and Intelligent Operations centers. With 513,000 people serving clients in more than 120 countries, Accenture brings continuous innovation to help clients improve their performance and create lasting value across their enterprises. Visit us at www.accenture.com.

For Microsoft

Microsoft Media Relations
WE Communications for Microsoft
(425) 638-7777
rrt@we-worldwide.com

For Halliburton

Investors:
Abu Zeya
Halliburton, Investor Relations
Investors@Halliburton.com
281-871-2633

Media:
Emily Mir
Halliburton, Public Relations
PR@Halliburton.com
281-871-2601

For Accenture
 Christian Harper
Accenture Media Relations
Christian.harper@acccenture.com
516-434-8615

Oil and gas after COVID-19: The day of reckoning or a new age of opportunity?

The oil and gas industry is experiencing its third price collapse in 12 years. After the first two shocks, the industry rebounded, and business as usual continued. This time is different. The current context combines a supply shock with an unprecedented demand drop and a global humanitarian crisis. Additionally, the sector’s financial and structural health is worse than in previous crises. The advent of shale, excessive supply, and generous financial markets that overlooked the limited capital discipline have all contributed to poor returns. Today, with prices touching 30-year lows, and accelerating societal pressure, executives sense that change is inevitable. The COVID-19 crisis accelerates what was already shaping up to be one of the industry’s most transformative moments.

While the depth and duration of this crisis are uncertain, our research suggests that without fundamental change, it will be difficult to return to the attractive industry performance that has historically prevailed. On its current course and speed, the industry could now be entering an era defined by intense competition, technology-led rapid supply response, flat to declining demand, investor skepticism, and increasing public and government pressure regarding the impact on climate and the environment. However, under most scenarios, oil and gas will remain a multi-trillion-dollar market for decades. Given its role in supplying affordable energy, it is too important to fail. The question of how to create value in the next normal is therefore fundamental.

To change the current paradigm, the industry will need to dig deep and tap its proud history of bold structural moves, innovation, and safe and profitable operations in the toughest conditions. The winners will be those that use this crisis to boldly reposition their portfolios and transform their operating models. Companies that don’t will restructure or inevitably atrophy.

A troubled industry enters the crisis

The industry operates through long megacycles of shifting supply and demand, accompanied by shocks along the way. These megacycles have seen wide swings in value creation.

After the restructuring of the early 1980s, the industry created exceptional shareholder value. From 1990 to 2005, total returns to shareholders (TRS) in all segments of the industry, except refining and marketing companies, exceeded the TRS of the S&P 500 index. Oil and gas demand grew, and OPEC helped to maintain stable prices. Companies kept costs low, as memories from the 1980s of oil at $10 per barrel (bbl) were still acute. A new class of supermajor emerged from megamergers; these companies created value for decades. Similarly, the “big three” oil-field service equipment (OFSE) companies emerged. Political openings and new technologies created an opportunity for all.

From 2005 to January 2020, even as macro tailwinds such as strong demand growth and effective supply access continued, the global industry failed to keep pace with the broader market. In this period, the average of the oil and gas industry generated annual TRS growth about seven percentage points lower than the S&P 500 (Exhibit 1). Every subsegment similarly underperformed the market, and independent upstream and OFSE companies delivered zero or negative TRS. The analysis excludes companies that were not listed through this period (including some structurally advantaged national oil companies, and private companies).

In the early years of this period, the industry’s profit structure was favorable. Demand expanded at more than 1 percent annually for oil and 3 to 5 percent for liquefied natural gas (LNG). The industry’s “cost curves”—its production assets, ranked from lowest to highest cost—were steep. With considerable high-cost production necessary to meet demand, the market-clearing price rose. The same was true for both gas and LNG, whose prices were often tightly linked to oil. Even in downstream, a steep cost curve of the world’s refining capacity supported high margins.

Encouraged by this highly favorable industry structure and supported by an easy supply of capital seeking returns as interest rates fell, companies invested heavily. The race to bring more barrels onstream from more complex resources, more quickly, drove dramatic cost inflation, particularly in engineering and construction. These investments brought on massive proved-up reserves, moving world supplies from slightly short to long.

Significant investment went into shale oil and gas, with several profound implications. To begin with, shale reshaped the upstream industry’s structure. As shale oil and gas came onstream, it flattened the production-cost curve (that is, moderate-cost shale oil displaced much higher-cost production such as oil sands and coal gas), effectively lowering both the marginal cost of supply and the market-clearing price (Exhibit 2).

In another wrinkle, the rise of shale made it more challenging for OPEC to maintain market share and price discipline. While OPEC cut oil and natural gas liquids production by 5.2 million barrels per day (bpd) since 2016, shale added 7.7 million bpd over this timeframe, taking share and limiting price increases. When the industry no longer needs a decade to find and develop new resources but can turn on ample supply in a matter of months, it will be hard to repeat the run-up in prices of 2000–14.

Historically, price wars wipe out poor performers and lead to consolidation. But the capital markets were generous with the oil industry in 2009–10 and again in 2014–16. Many investors focused on volume growth funded by debt, rather than operating cash flows and capital discipline, in the belief that prices would continue to rise and an implied “OPEC put” set a floor.

It hasn’t worked out that way.

 

Challenges today and tomorrow

The combination of the COVID-19 pandemic demand disruption and a supply glut has generated an unprecedented crisis for the industry.

Short-term scenarios for supply, demand, and prices

Under most best-case scenarios, oil prices could recover in 2021 or 2022 to pre-crisis levels of $50/bbl to $60/bbl. Crude price differentials in this period are also likely to present both challenges and opportunities. The industry might even benefit from a modest temporary price spike, as today’s massive decline in investment results in tomorrow’s spot shortages. In two other scenarios we modeled, those price levels might not be reached until 2024. In a downside case, oil prices might not return to levels of the past. In any case, oil is in for some challenging times in the next few years.

Regional gas prices could fall much lower than in the previous megacycle. Shale gas has unlocked abundant gas resources at breakeven costs less than $2.5/MMBtu to $3.0/MMBtu.1 The pandemic has had an immediate impact, lowering gas demand by 5 to 10 percent versus pre-crisis growth projections. With North America becoming one of the largest LNG exporters by the early 2020s and a sharply oversupplied LNG market, regional gas prices in Europe and Asia will be driven by prices at Henry Hub, plus cash costs for transportation and liquefaction (a premium of about $1/MMBtu to $2/MMBtu).

Demand for refined products is down at least 20 percent, and has plunged refining into crisis. We think it will be two years at least before demand recovers, with the outlook for jet fuel particularly bleak.

The immediate effects are already staggering: companies must figure out how to operate safely as infection spreads and how to deal with full storage, prices falling below cash costs for some operators, and capital markets closing for all but the largest players.

Long-term challenges

Looking out beyond today’s crisis toward the late 2030s, the macro-environment is set to become even more challenging. Start with supply and demand. We expect growth in demand for hydrocarbons, particularly oil, to peak in the 2030s, and then begin a slow decline.

Excess capacity in refining will be exposed, putting downward pressure on profits—driven by marginal pricing and, in some cases outside the growing non-OECD2 demand markets, by the economics of some refiners that seek to avoid the high cost of closing assets.

The upstream cost curve will likely stay flat. While geopolitical risks will continue to be a major factor affecting supply, new sources of low-cost, short-cycle supply will reduce the amplitude and duration of price fly-ups. The battered shale oil and gas subsector will nonetheless continue to provide supply that can be rapidly brought onstream. Its resilience might even improve as larger, stronger players consolidate the sector. Declining demand, driven by the energy transition, and global oversupply will make the task of OPEC and OPEC++ harder rather than easier.

Global gas and LNG will have a favorable role in the energy transition, ensuring a place in the future energy mix, supported by the continual demand growth in the coming decade. However, in LNG, the expected and potential cyclical capacity expansion over the decade will add pressure and volatility to global LNG contract pricing, and hence to regional gas prices. In the long term (post-2035), gas will face the same pressures as oil with peak demand and incremental economics driving decision making.

The challenge of the energy transition will continue. Today, governments are intently focused on managing the COVID-19 pandemic and mitigating the effects on economies, which is deflecting attention away from the energy transition. That said, the climate and environment debate is unlikely to go away. The innovation that has lowered costs for wind, solar, and batteries will continue and the decarbonization will remain an imperative for the industry. Negative public sentiment and investor/lender pressure that the industry has endured in the past may turn out to be mild compared with the future. The energy transition and decarbonization may even be accelerated by the current crisis.

A growing number of investors are questioning whether today’s oil and gas companies will ever generate acceptable returns. And their role in the energy transition is also uncertain. Oil and gas companies will have to prove that they can master this space. Discipline in finance, capital allocation, risk management, and governance will be critical.

The crisis as a catalyst

The pandemic is first and foremost a humanitarian challenge, as well as an unprecedented economic one. The industry has responded with a Herculean effort to successfully and safely operate essential assets in this challenging time. The current crisis will have a profound impact on the industry, both short and long term. How radically the oil and gas ecosystem will reconfigure, and when, will depend on potential supply-demand outcomes and the actions of other stakeholders, such as governments, regulators, and investors. In any scenario, however, we argue that the unprecedented crisis will be a catalytic moment and accelerate permanent shifts in the industry’s ecosystem, with new future opportunities.

Implications for the industry

All companies are rightly acting to protect employees’ health and safety, and to preserve cash, in particular by cutting or deferring discretionary capital and operating expenditures and, in many cases, distributions to shareholders. These actions will not be enough for financially stretched players. We are likely to see an opportunity for a profound reset in many segments of the industry.

Upstream. A broad restructuring of several upstream basins will likely occur, underpinned by the opportunity created by balance-sheet weaknesses, particularly in US onshore and other high-cost mature basins. We could see the US onshore industry, which currently has more than 100 sizable companies, consolidate very significantly, with only large at-scale companies and smaller, truly nimble, and innovative players surviving. Broad-based consolidation could be led by “basin masters” to drive down unit costs by exploiting synergies. In the shale patch alone, we estimate that economies of skill and scale, coupled with new ways of working, could further reduce costs by up to $10/bbl, lowering shale’s breakeven point and improving supply resilience.

Downstream. Closing refineries and other assets with high costs or poor proximity to growing non-OECD markets were going to be necessary anyway when oil demand begins a secular decline. However, as we saw in the 1980s and 1990s, governments may intervene to prop up inefficient assets, which will place additional pressure on advantaged assets elsewhere in the global refining ecosystem. Consolidation, another wave of efficiency efforts, and the hard work needed to wring out every last cent of value from optimizing refineries and their supply chains are the likely industry response. In the medium term, the value of retail networks (and access to end customers) could increase.

Midstream. Well-located midstream assets supported by contracts with creditworthy counterparties have proven a successful business model. Midstream may well continue to be a value-creating component of the oil and gas value chain, however, as demand peaks in the 2030s—there is likely to be downward pressure on rates driven by pipe-on-pipe competition.

Petrochemicals. Petrochemicals have been and could continue to be a bright spot in the portfolio for leading players. Disciplined investment in advantaged assets (such as at-scale integrated refining/petrochemical installations) that feature distinctive technologies and privileged markets should enable value creation.

Global gas and LNG. Gas is the fastest-growing fossil fuel, with robust demand driven by the energy transition (for example, the shifts away from coal, and from dispatchable backup to renewables). However, the total extent of greenhouse-gas emissions is still being calculated for some LNG value chains. We estimate that global gas demand will peak in the late 2030s as electrification of heating and development of renewables may erode long-term demand. This, combined with midterm volatility, could lead to further consolidation and to an industry operating on incremental economics.

Oil-field services and equipment (OFSE) and supply chain. Much of the oil and gas supply industry was in a dire position coming into the crisis; significant over-capacity had emerged, and profitability collapsed after 2014. Despite a wave of bankruptcies and restructurings, the industry has not experienced the radical consolidation, capacity reductions, and capability upgrades needed. This restructuring may well happen now, with asset liquidation that resembles the 1980s oil bust more than the soft 2015–20 financial restructuring, and a new wave of business and supply-chain reconfiguration, technological acceleration, and partnership with customers.

National Oil Companies. National Oil Companies (NOCs) will be under additional pressure due to their important role as contributors to national budgets and governments’ societal needs. The difficult choices between industry supply discipline and market-share protection will accentuate. For NOCs not blessed with the lowest-cost resources, the pressure for fundamental change (for example, through privatization or a rethinking of collaboration with IOCs and OFSE companies) will be intense.

New businesses related to the energy transition and renewables will continue to emerge, particularly during the crises. The returns for some of these opportunities remain unclear, and the oil and gas industry will have to prove whether it can be a natural and leading participant in these businesses. Hydrogen, ammonia, methanol, new plastics, and carbon capture, utilization, and storage (CCUS) could all be interesting areas for the oil and gas industry.

The current crisis will have a profound impact on the industry, both short and long term.

How to win in the new environment

Some companies whose business models or asset bases are already distinctive can thrive in the next normal. But for most companies, a change in strategy, and potential business model, is imperative.

Learning from others

It is instructive to seek inspiration from other industries that experienced sector-wide change, and how the leaders within these industries emerged as value creators. The common thread in these examples is a large reallocation of capital informed by a deep understanding of market trends and future value pools, the value of focused scale, and a willingness to fundamentally challenge and transform existing operating models and basis for competition.

Steel experienced both declining demand and stranded assets due to global shifts in demand, that structurally destroyed value. However, a few players used different strategies to protect value. Mittal Steel built a model around acquiring assets with structural advantage (such as those in insulated markets, and some that allowed backward integration into advantaged raw-material supply) and then cutting costs and improving operations. Additionally, it initiated significant industry consolidation. Nucor combined industry-leading operational capabilities with a first-mover status in electric-arc furnace technology. Others focused on scale and technology in profitable niches like seamless pipe.

In automobile manufacturing, faced with rising Asian competition, US and European companies had to change. Fiat Chrysler Automobiles aggressively restructured its business model and culture by pursuing transformative mergers (Chrysler first, PSA Group lately) to gain scale in, or access to, preferred market segments, and to add global brands to its portfolio. It subsequently drove platform sharing across models and integrated supply-chain partners into its ecosystem.

In materials, 3M found a way to innovate on commodity materials that enabled it to identify high-value end markets. A telecom-equipment manufacturing company came close to the demise when the telecom business collapsed at the end of the dotcom boom. It boldly reallocated resources and conducted programmatic M&A to become a leading producer of LCD glass for the booming mobile-device market.

In banking, JPMorgan Chase used its “fortress-like” balance sheet during the financial crisis to make attractive acquisitions and relentlessly pursue market leadership in segments it believed in. It was not always the first mover but mobilized significant resources (people and capital) against several big bets. ING, the Dutch banking group, undertook a radical digital and agile transformation to fundamentally change its operating platform, which it thinks is now properly geared for the future.

Some traditional and existing models will still apply

Traditionally the super-major approach has been one model for value creation. Companies with scale, strong balance sheets, best-in-class integrated portfolios, advantaged assets, and superior operational abilities should create value even in a challenging future. Basin leadership has also long been a source of distinctiveness and value creation in oil and gas. Similarly, low-cost commodity suppliers with first-quartile assets have also thrived.

Finally, the industry features some focused business models that create value through scale, capability and operational efficiencies in specific segments—such as Vitol in trading, Enterprise Products Partners in midstream, Ørsted in offshore wind, and Quantum Energy Partners in private equity. Undoubtedly there will be similar opportunities to build commercially disciplined niche companies in the future.

Questions for leaders and emerging insights—the return of strategy

While the current crisis is justifiably consuming leadership time and attention, many are thinking through how to lead their companies after the crisis and are posing existential questions about their reasons for being and basis for distinctiveness. Different strategic choices are available (such as basin master, midstream and trading leader, technology specialist, first-quartile low-cost producer, value-chain integrator, energy transition specialist, and advantaged integrated refining/petrochemical player, among others). It will be unacceptable not to make clear choices. The value of the traditional multi-business model is often not sufficient enough to overcome bad operational management, poor capital allocation, or structurally disadvantaged assets. Will some large companies survive in their current form? What is the role of independents and mid-size players? How will NOCs thrive and continue to play their important societal roles in the future?

Will different forms of partnership with the supply chain be an important part of future business models? How should companies structure relationships with digital and advanced analytics companies to transform operations and to support new business models? Can technology and innovation unlock new growth for the industry: What would it take to deliver new LNG projects in a fundamentally different way at $300/ton and displace coal completely? Can the costs of CO2 mitigation be fundamentally lowered? In an era of abundance, will value flow to those that own the customer relationship and integrated value chains? Should companies make a radical shift toward renewables and away from oil and gas?

In answering these questions, companies should base their responses on three givens. The opportunity to lead has never been better—separation between market leaders and laggards will be increasingly sharp. Shaping regulation will matter, and enforcing operating standards will benefit industry and market leaders. Similarly, resilience and balance-sheet strength are non-negotiable. A new, strategic view on what the capital structure should look like, and the resultant dividend policy, is needed.

Taking bold action during the crisis to secure resilience and accelerated repositioning

Hard questions, indeed. In the meantime, winners will accept the crisis for what it is: a chance to form their own views of the future and to lead to capture new opportunities. Leaders will adopt tailored strategies that fit within their specific environment and markets in which they choose to compete, and the capabilities they bring (such as low-cost production, regional-gas or downstream-oil market leadership, value-chain integration, and specialized strengths in for example retail, trading, and distribution). In our view, all companies should act boldly on five themes, consistent with their chosen strategy:

  1. Reshape the portfolio, and radically reallocate capital to the highest-return opportunities. Our studies across multiple industries show that the degree of dynamic capital reallocation strongly correlates to long-term value creation (Exhibit 3). Companies should make tough and fundamental choices across the asset base and permanently reallocate capital away from lower-return businesses toward those best aligned with future value creation and sources of distinctiveness. Some companies may choose this moment to accelerate their pivot toward the energy technologies of the future. All this needs to happen in an environment in which companies must also rebuild trust with the capital markets by delivering attractive returns on capital.

  2. Take bold M&A moves. Could this be another age of mergers—potentially with carve-outs and spin-outs? Is now the time to drive massive consolidation and rationalization, and basin mastery, in US onshore basins such as the Permian, and across basins globally? Winners will emerge with advantaged portfolios that will be resilient to longer-term trends. They should settle for nothing less than the absolutely best positioned assets in upstream, refining, marketing, and petrochemicals.

  3. Unlock a step-change in performance and cost competitiveness through re-imagining the operating model. Overhead levels at some companies are more than double what they were in 2005. In most cases, these bureaucracies do not improve safety or reliability—and they certainly slow decision making. We believe that G&A and operating costs can be reduced by another 30 to 50 percent. Throughput from existing assets can also be improved significantly—in upstream, average performers have more than 20 percent opportunity, and even top-quartile performers can improve production by 3 to 5 percent. Leading companies will redouble their efforts in this moment, protecting or even scaling up technology, digital, and artificial-intelligence investments; and taking inspiration from some of the new approaches emerging from remote working, so that they do not return to business as usual once the crisis ends. The COVID-19 crisis, which has forced companies to operate in new ways, may be a catalyst to rethink the size and role of the functional teams, field crews, and management processes needed to run an efficient oil and gas company.

  4. Ensure supply-chain resilience through redefining strategic partnership approaches. Leading operators will act now to ensure resilience, in large part by promoting new commercial and collaborative models with an ecosystem of suppliers to radically simplify standards, processes, and interfaces; lower costs; and increase the speed and quality of the entire system. Deep strategic integration into the supply chain will be critical. “Three bids and a buy” from a deeply distressed supply chain is not a winning model. The OFSE supply chain needs to gain further scale and be able to invest in technology to reduce system costs. Within capital projects, we expect multi-project strategic cooperation and integrated project delivery (IPD) to become much more prevalent; IPD contracting aligns all participants, including sub-contractors, to one over-arching project goal.

  5. Create the Organization of the Future, in both talent and structure. The oil and gas industry is no longer the premier employer of choice in many markets and is struggling to attract not only the best engineers but also the best new talent in areas such as digital, technology, and commercial. All are needed to drive business model transformation. The root causes are partly perceptual, as many young people think the sector is placed on the wrong side of the transition. But another cause is the misalignment between the career-progression timeframes and work-life choices the industry offers and the expectations of newer generations of talent. The industry can learn from this crisis. It can radically flatten hierarchies, reduce bureaucracy, and push decision making to the edge—in short, embed more agile ways of working. A new blend of talent can re-animate some of the innovative and pioneering mindsets from past periods.


Industry fundamentals have changed and the rules of the next normal will be tough. But strong performers—with resilient portfolios, innovation, and superior operating models, potentially very different from today—can outperform. The time for visionary thinking and bold action is now.

About the author(s)

Filipe Barbosa is a senior partner, Scott Nyquist is a senior adviser, and Kassia Yanosek is a partner, all in McKinsey’s Houston office. Giorgio Bresciani is a senior partner in the London office, where Pat Graham is a partner.

The authors would like to thank Nikhil Ati, Ivo Bozon, Dumitru Dediu, Luciano Di Fiori, Mike Ellis, Bob Frei, Tom Grace, Stephen Hall, Thomas Hundertmark, Sanjay Kalavar, Matt Rogers, Thomas Seitz, Namit Sharma, Paul Sheng, and Sven Smit for their contributions to this article.

McKinsey

www.mckinsey.com

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BHGE unveils LUMEN

  • At its 20th Annual Meeting in Florence, BHGE makes the commitment to reduce CO2 equivalent emissions 50 percent by 2030 and achieve net zero by 2050

  • BHGE will support customers’ efforts to reduce the carbon footprint of their operations by investing in its portfolio of lower carbon products and services

  • New and future technologies launched at the annual event include LUMEN, which is both a wireless ground-based and aerial drone-based methane detection system; as well as a turbine powered 100 percent by hydrogen

  • BHGE’s Gaffney, Cline and Associates has launched its own Carbon Management Practice, the first oil and gas consultancy to offer a quantitative assessment of the carbon intensity of oil and gas assets, evaluation of carbon solutions and the accreditation of emission reductions

FLORENCE, ITALY — 28 January 2019 – On the first day of its 20th Annual Meeting in Florence, Italy, Baker Hughes, a GE company (NYSE: BHGE), announced its commitment to reduce its CO2 equivalent (eq.) emissions 50 percent by 2030,* achieving net-zero CO2 eq. emissions by 2050.  The company also said it will invest in its portfolio of advanced technologies to assist customers with reducing their carbon footprint.

Net Zero Carbon Emissions

BHGE has already achieved a 26 percent reduction in its emissions since 2012 through a commitment to new technology and operational efficiencies.  BHGE will continue to employ a broad range of emissions reduction initiatives across manufacturing, supply chain, logistics, energy sourcing and generation.  BHGE has established a global additive manufacturing technology network with a mission to bring commercial-scale production closer to customers, reducing transportation impact and associated emissions.

“Oil and gas will continue to be an important part of the global energy mix, and BHGE is committed to investing in smarter technologies to advance the energy industry for the long-term,” said Lorenzo Simonelli, chairman and CEO of BHGE. “Managing carbon emissions is an important strategic focus for our business.   We believe we have an important role to play as an industry leader and partner.  BHGE has a long legacy of pushing the boundaries of technology and operating efficiency. Today we take this to the next level by committing to ambitious new goals for ourselves, and to provide lower carbon solutions expected by customers and society.”

New Carbon Management Practice

To further industry and customer efforts to reduce carbon emissions, BHGE’s Gaffney, Cline and Associates has launched a new Carbon Management Practice. This is the first oil and gas consultancy to offer a quantitative assessment of carbon intensity, evaluation of carbon solutions and the accreditation of emission reductions. This new practice helps governments, energy companies and the financial community understand and solve energy transition issues related to oil and gas resources, assets and investments.

Technology Partner to Customers

At its Annual Meeting, BHGE announced new and existing technologies that support operators’ efforts to reduce their carbon footprint:  

  • LUMEN, a full-suite of methane monitoring and inspection solutions capable of streaming live data from sensors to a cloud-based software dashboard for real-time results.  The platform consists of two seamlessly connected formats – a ground-based solar-powered wireless sensor network, and a drone-based system for over-air monitoring, – ensuring methane emissions rates and concentration levels are monitored and located as efficiently and accurately as possible. This builds on BHGE’s extensive portfolio of remote inspection and sensing technologies.

  • An agreement with H2U, Australia’s leading Hydrogen infrastructure developer, to configure BHGE’s NovaLT gas turbine generator technology to operate 100 percent on hydrogen for the Port Lincoln Project, a green hydrogen power plant facility in South Australia.

The new technologies build on BHGE’s expanding lower-carbon technology portfolio, which includes:

  • Modular Gas Processing: Modular gas processing at Nassiriya and Al Gharraf oilfields in Iraq will recover 200 million standard cubic feet per day of flare gas, reducing emissions by 5.7 million metric tons per year of CO2 equivalent, and monetizing the recovered gas. The recovered gas will be processed into dry gas, liquefied petroleum gas for cooking, and condensate, and will support domestic power generation as well as exports. An additional net 3.9 million metric tons of CO2 eq. emissions reductions are possible annually if incremental power generation is fueled by natural gas, displacing oil.  Flare gas recovery and use represent one of the largest emission reduction opportunities in the global oil & industry.

  • LM9000 Gas Turbine: BHGE’s most advanced aero-derivative gas turbine, introduced in 2017, was designed to allow the LNG train startup in the pressurized condition without venting process gas.  Its flexible fuel technology reduces emissions while eliminating water use in emissions abatement.  The LM9000 delivers 50 percent longer maintenance interval, 20 percent more power and 40 percent lower NOx emissions, resulting in 20 percent lower cost of ownership for LNG customers.

  • Integrated Compressor LineThis high-efficiency offshore compressor operates with zero emissions. It is driven by a high-speed electric motor in a single sealed casing and its rotor is levitated by active magnetic bearings (AMBs), allowing exceptional efficiency and reliability.

  • flare.iQ: flare.IQ™ provides highly accurate, near-continuous control of downstream flare performance by optimizing combustion efficiency, allowing operators to reduce flaring-related emissions by up to 12,100 metric tons of CO2 equivalent per flare annually. If deployed globally, flare.iQ could reduce annual emissions by 190 million metric tons of CO2 eq.

  • NextSource Modular CO2 Capture:  NextSource converts thermal energy from rich burn Waukesha engine exhaust to provide low-cost CO2 for oil and gas consumers. In the process, each four-engine pad reduces emissions by 16,200 metric tons of CO2 equivalent annually or 60 percent compared to the no-capture scenario. In addition, because CO2 is captured near the well site, emissions are avoided from not having to transport liquid CO2 from a remote location to the well site.

Visit https://annualmeeting.bhge.com to learn more about the Florence event including the conference agenda and speakers guide, and where the full proceedings from the Annual Meeting will be shared at the close of the event.

**BHGE’s 2030 emissions reduction targets and performance are based on scope 1 & 2 emissions for 2017 and baseline year 2012, as reported to the Carbon Disclosure Project..

Secrets of the Deep: The Stones Metocean Monitoring Project | Sustainability at Shell

Shell has opened up parts of its Stones Deepwater mooring line to universities and research institutions. The Stones Metocean Monitoring Project provides access to data – unreachable until now – helping to build scientific understanding of the Gulf of Mexico’s role in global climate and ocean circulation.

Transcript: https://s00.static-shell.com/content/…

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Published by Shell on Nov 29, 2017

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Study: Filtration a Viable Option for Produced Water from the Marcellus Shale

The rising production of natural gas from hydraulically fractured wells in Appalachia generates along with it contaminated produced water that must be carefully disposed of. Researchers at Pennsylvania State University say that producers would be wise to consider the environmental risks associated with the most commonly used disposal practice of underground injection, and instead adopt more environmentally friendly and sustainable innovations in water filtration.

The study, Sustainability in Marcellus Shale Development, published by Penn State’s College of Engineering in conjunction with Chevron, notes that produced and flowback water from the prolific Marcellus Shale in Pennsylvania is most commonly disposed of through injection into saltwater injection wells drilled far below the deepest known aquifer.

But although this method is the cheapest available and most frequently used, it brings with it the potential for surface spills and casing leaks that can contaminate freshwater, as well as the risk of activating dormant faults and causing earthquakes.

Disposing Fracked Water

“During the hydraulic fracturing process, water and chemicals are used to stimulate the fissures in the rock in order to extract the natural gas. Water is mixed with sand and other chemicals and then injected into the well. After creating cracks in the Marcellus Shale, flowback water, a brine solution with heavy metals and chemicals, quickly comes back. Typically, this flowback water is stored in tanks or pits before treatment, recycling, or disposal,” according to the report, co-written by Kyle Bambu, Mike Spero, and Harry Polychronopoulos.

The most common way to dispose of this produced water is by pumping it into saltwater disposal wells that are drilled hundreds below the deepest known aquifers. But Pennsylvania’s unique geology is not well suited for such wells. At the time the study was published in Fall 2016, there were 144,000 Class II injection wells in the US and only eight of them were Class II salt water disposal wells in Pennsylvania. These eight wells combined accepted 8,667 barrels per day of brine, while similar wells operated in Texas can each dispose of more than 26,000 b/d of brine.

According to the report, the average cost to dispose of one bbl of fluid can range from as low as 25¢/bbl if the oil company operates its own disposal well, to anywhere from 50¢/bbl to $2.50/bbl if a commercial saltwater disposal well is used. The cost of using disposal is further increased by the cost of transportation.

“In northern Pennsylvania, where commercial disposal wells aren’t plentiful, the brine water may have to be transported to Ohio or West Virginia. This can increase costs by $4.00 to $6.00 a barrel, bringing the net cost of disposal in the Marcellus Shale region to $4.50/bbl to $8.50/bbl,” the study said.

The use of underground disposal wells is not without risk, and frequent concerns include the potential for groundwater contamination and induced seismic activity. In Youngstown, Ohio, the researchers noted that a Class II disposal well for fracking wastewater was linked to seismic activity after it activated a previously unknown fault line. That well was blamed for 10 minor earthquakes, the largest of which is a magnitude of 3.9. A spate of earthquakes in Oklahoma in recent years has likewise been linked to the increased injection of water into disposal wells.

The need to dispose of produced water in Pennsylvania has become more pressing in recent years as natural gas production from the prolific Marcellus and neighboring Utica shales has taken off.  Data from the federal Energy Information (EIA) Administration show that output from the shale formations more than tripled Appalachian gas production from 7.8 billion cubic feet per day in 2012 to 23.8 Bcf/d in 2017 (EIA). These plays are credited for driving growth in US natural gas production since 2012 and have played a critical role in enabling low domestic prices and increasing exports.

The Water Filtration Alternative

Researchers note that a number of alternatives to disposal wells are emerging at varying levels of cost. These largely involve treating the produced water to remove its various contaminants, which can include radioactive substances, heavy metals, and high concentrations of salt. Traditional wastewater treatment plants cannot be used because they lack the sufficient processes needed to clean this water.

The most cost competitive alternative to underground injection highlighted by researchers is the option of using a membrane to clean the brine produced water. The company Oasys Water offers a system that drives the brine solution through a series of semi-permeable membranes at a cost of nearly $2/bbl of water. The water that emerges from this process is clean enough to be discharged into streams or drainage systems.

Other potential treatments on the horizon that require further research include the option of boiling the water. However, researchers note that the cost of using this process can run upwards of $17/bbl and the heavy salt causes extreme wear and tear to the requisite industrial boilers, resulting in massive equipment replacement costs.

Lastly, the study says the process of electrodialysis could be used to separate water from contaminants. Researchers at the Massachusetts Institute of Technology have found that an electrical current can be used to separate fresh water from a salty solution. Salt is an effective conductor of electricity and successive stages of electrodialysis can remove most contaminates. But this process has not been tested in the oil and gas industry and there are not commercial treatment options available.

Researchers ultimately concluded that while the common practice of injecting produced water into disposal wells is relatively cheap, this practice comes with high environmental risks. These risks include the potential for groundwater contamination that is caused by surface spills or breaks in the tubing for saltwater disposal wells and even induced seismic activity.

At present, the impetus for improving produced water disposal practices is driven primarily by the sustainability practices of each producer and not government regulations. Researchers found that the oil and gas industry is exempt from some of the most stringent federal environmental regulations, like the Safe Drinking Water Act the Clean Water Act, but noted that states have been working to impose their own rules to address areas of concern. For instance, Pennsylvania in recent years adopted new guidelines intended to prevent spills and releases of harmful substances.

Today’s Best Option

The study ultimately recommends Oasys Water’s membrane filtration as the best option for disposing of produced water today. Researchers said that while using this method can result in slightly higher costs for water treatment and transportation, it appears to be the most sustainable solution until other technological advances are advanced in the future.

“This (membrane) system was recommended because of its relatively cheap cost yet adherence to sustainability and environmentally friendly concerns,” the study said.

To read a PDF of the Penn State study, click here.

Subsurface Data in the Oil and Gas Industry

Probing beneath the Earth’s surface for exploration and hazard mitigation

Drilling for oil and gas is expensive. A single well generally costs $5-8 million onshore and $100-200 million or more in deep water.1 To maximize the chances of drilling a productive well, oil and gas companies collect and study large amounts of information about the Earth’s subsurface both before and during drilling. Data are collected at a variety of scales, from regional (tens to hundreds of miles) to microscopic (such as tiny grains and cracks in the rocks being drilled). This information, much of which will have been acquired in earlier exploration efforts and preserved in public or private repositories, helps companies to find and produce more oil and gas and avoid drilling unproductive wells, but can also help to identify potential hazards such as earthquake-prone zones or areas of potential land subsidence and sinkhole formation.

Mapping the Subsurface 1: Regional Data from Geophysics

In the 21st century, much is already known about the distribution of rocks on Earth. When looking for new resources, oil and gas producers will use existing maps and subsurface data to identify an area for more detailed exploration. A number of geophysical techniques are then used to obtain more information about what lies beneath the surface. These methods include measurements of variations in the Earth’s gravity and magnetic field, but the most common technique is seismic imaging.

Seismic images are like an ultrasound for the Earth and provide detailed regional information about the structure of the subsurface, including buried faults, folds, salt domes, and the size, shape, and orientation of rock layers. They are collected by using truck-mounted vibrators or dynamite (onshore), or air guns towed by ships (offshore), to generate sound waves; these waves travel into the Earth and are reflected by underground rock layers; instruments at the surface record these reflected waves; and the recorded waves are mathematically processed to produce 2-D or 3-D images of subsurface features. These images, which cover many square miles and have a resolution of tens to hundreds of feet, help to pinpoint the areas most likely to contain oil and/or gas.

A typical setup for offshore seismic imaging. Image Credit: U.S. Bureau of Ocean Energy Management.2

Mapping the Subsurface 2: Local Data from Well Logs, Samples, and Cores

Drilling a small number of exploratory holes or using data from previously drilled wells (common in areas of existing oil and gas production) allows geologists to develop a much more complete map of the subsurface using well logs and cores:

  • well log is produced by lowering geophysical devices into a wellbore, before (and sometimes after) the steel well casing is inserted, to record the rock’s response to electrical currents and sound waves and measure the radioactive and electromagnetic properties of the rocks and their contained fluids.3 Well logs have been used for almost 100 years4 and are recorded in essentially all modern wells.

  • core is a cylindrical column of rock, commonly 3-4 inches in diameter, that is cut and extracted as a well is drilled. A core provides a small cross-section of the sequence of rocks being drilled through, providing more comprehensive information than the measurements made by tools inside the wellbore.5 Core analysis gives the most detailed information about the rock layers, faults and fractures, rock and fluid compositions, and how easily fluids (especially oil and gas) can flow through the rock and thus into the well.

By comparing the depth, thickness, and composition of subsurface rock formations in nearby wells, geoscientists can predict the location and productive potential of oil and gas deposits before drilling a new well. As a new well is being drilled, well logs and cores also help geoscientists and petroleum engineers to predict whether the rocks can produce enough oil or natural gas to justify the cost of preparing the well for production.7

A box containing 9 feet of 4-inch diameter core from the National Petroleum Reserve, Alaska, showing the fine-scale structure and composition of the rock layers being drilled. Image Source: U.S. Geological Survey.6

Data Preservation

Preservation of subsurface data is an ongoing challenge, both because there is so much of it and because a lot of older data predate computer storage. A modern seismic survey produces a few to thousands of terabytes of data;8 state and federal repositories collectively hold hundreds of miles of core;9 and millions of digital and paper records are housed at state geological surveys. For example, the Kansas Geological Society library maintains over 2.5 million digitized well logs and associated records for the state.10 Oil companies also retain huge stores of their own data. Preserving these data, which cost many millions of dollars to collect, allows them to be used in the future for a variety of purposes, some of which may not have been anticipated when the data were originally collected. For example, the shale formations that are now yielding large volumes of oil and natural gas in the United States were known but not considered for development for decades while conventional oil and gas resources were being extracted in many of the same areas. Archived well logs from these areas have helped many oil and gas producers to focus in on these shale resources now that the combination of hydraulic fracturing and horizontal drilling allow for their development.

Data for Hazard Mitigation

Oil and gas exploration is a major source of information about the subsurface that can be used to help identify geologic hazards:

  • Since 2013, the oil and gas industry has provided more than 2,500 square miles of seismic data to Louisiana universities to assist with research into the causes and effects of subsidence in coastal wetlands. For example, seismic and well data have been used to link faults to historic subsidence and wetland loss near Lake Boudreaux.11

  • To improve earthquake risk assessment and mitigation in metropolitan Los Angeles, scientists have used seismic and well data from the oil and gas industry to map out previously unidentified faults. This work was motivated by the 1994 Northridge earthquake, which occurred on an unknown fault that was not visible at the Earth’s surface.12

More Resources

U.S. Geological Survey – National Geological and Geophysical Data Preservation Program.

References

1 U.S. Energy Information Administration (2016). Trends in U.S. Oil and Natural Gas Upstream Costs.
2 Bureau of Ocean Energy Management – Record of Decision, Atlantic OCS Region Geological and Geophysical Activities.
3 Varhaug, M. (2016). Basic Well Log Interpretation. The Defining Series, Oilfield Review.
4 Schlumberger – 1920s: The First Well Log.
5 AAPGWiki – Overview of Routine Core Analysis.
6 Zihlman, F.N. et al. (2000). Selected Data from Fourteen Wildcat Wells in the National Petroleum Reserve in Alaska. USGS Open-File Report 00-200. Core from the well “East Simpson 2”, Image no. 0462077.
7 Society of Petroleum Engineers PetroWiki – Petrophysics.
8 “Big Data Growth Continues in Seismic Surveys.” K. Boman, Rigzone, September 2, 2015.
9 U.S. Geological Survey Core Research Center – Frequently Asked Questions.
10 Kansas Geological Society & Library – Oil and Gas Well Data.
11 Akintomide, A.O. and Dawers, N.H. (2016). Structure of the Northern Margin of the Terrebonne Trough, Southeastern Louisiana: Implications for Salt Withdrawal and Miocene to Holocene Fault Activity. Geological Society of America Abstracts with Programs, 48(7), Paper No. 244-2.
12 Shaw, J. and Shearer, P. (1999). An Elusive Blind-Thrust Fault Beneath Metropolitan Los Angeles. Science, 283, 1516-1518.

Date updated: 2018-06-01
Petroleum and the Environment, Part 23/24
Written by E. Allison and B. Mandler for AGI, 2018

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