BHGE Shares Strategy for Integration of Services, Products, and Digital Platforms
Pam Boschee, Senior Editor
Marking 100 days as a new company after the merger of Baker Hughes and GE Oil and Gas, Baker Hughes, a GE company (BHGE), shared its strategies and plans for taking a fullstream approach to global oilfield services, products, and digital capabilities to improve productivity, safety, and project economics.
Speaking at the SPE Annual Technical Conference and Exhibition in October, Mathias Schlecht, BHGE vice president of enterprise technology, described the concept as the full integration of services from upstream to midstream to downstream. “We know how to get the molecules and transport and use them. From molecules to megawatts, and deep sea to the cloud.”
Accidental Discovery: Bitumen Pellets for Heavy Oil Transport
Stephen Whitfield, Senior Staff Writer
Researchers at the University of Calgary have developed something that may have a significant impact on the transport of heavy oil, and it is the size of a pill.
The discovery is a pellet, self-sealing with a liquid core of either bitumen or heavy oil within a super-viscous, semi-solid, or solid skin that reduces the chance of a damaging spill during transport. The pellets can be designed to be buoyant and safe if they are spilled into the environment by incorporating agents within the pellets, like gas bubbles, catalysts, and solvents. Their outer coating is unreactive, making them much less likely to cause environmental damage than a liquid heavy oil or bitumen spill.
Jones Energy CEO Tells of Company’s Transformation
Joel Parshall, JPT Features Editor
Jones Energy CEO Jonny Jones described his company’s transformation from a small private entity to a publicly traded company in a talk in October at the Leaders in Industry Luncheon, sponsored by the Independent Producers Association of America and the Texas Independent Oil Producers & Royalty Owners, at the Houston Petroleum Club.
Jones highlighted the company’s entry into the Merge oil play, a newly defined play at the junction of the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend, Anadarko and Canadian and Kingfisher [counties]) plays in central Oklahoma.
Largest Gulf of Mexico Lease Sale Announced
John Donnelly, JPT Editor
The US Department of the Interior in October proposed the largest oil and gas lease sale ever held in the United States—almost 77 million acres offshore Texas, Louisiana, Mississippi, Alabama, and Florida. The sale would be held in March 2018 and is attempted to revive interest in a sector that has been reeling since oil prices fell sharply beginning 3 years ago. The sale includes all available unleased areas on the Gulf ’s Outer Continental Shelf. The Trump administration said the auction should make the US energy industry stronger. This proposed sale follows a lease sale in the Gulf of Mexico in August that attracted $121 million in high bids on 90 offshore tracts.
After 3 tough years of cost cuts and downsizing, the oil industry is seeing signs of new life in a lower-price environment. Companies are hiring again, salaries have rebounded, and large producers are posting profits.
The oil and gas industry is finally hiring and may begin to face worker shortages in some areas. Since oil prices crashed in 2014, more than 440,000 jobs in the industry have been cut worldwide. But next year, almost 90% of employers expect that staffing levels will either stabilize or increase in 2018, according to a survey by NES Global Talent and oilandgasjobsearch.com. Almost 60% of employers expect to recruit significantly over the next year. Of the companies that are hiring, 23% expect to increase their workforce by 5%, 19% plan to increase staffing by between 5 and 10%; and 17% expect to increase hiring by more than 10%. Almost half of employers expect salaries to rise.
SPE’s annual industry salary survey also paints a brighter picture. Industry professionals reported average total compensation of $194,649 this year, a $9,000 increase from 2016 although still down from 2014 and earlier. Compared with 2016, mean base pay, other compensation, and total compensation all rose in 2017.
Oil prices have finally crossed the $50/bbl threshold, with Brent over $60/bbl in mid-November. Rising prices, along with sharp cost cutting, are leading to operator profits. The supermajors—including ExxonMobil, Total, Chevron, Shell, and BP—all posted healthy third-quarter earnings and solid year-over-year improvement in cash flow and profits. In delivering their earnings, both BP and Shell said they would remain profitable even if oil prices dipped into the high-$40/bbl range. The large service companies, such as Schlumberger, Baker Hughes, and Halliburton, were more circumspect in their outlooks but see a foundation laid for better days ahead.
OPEC also sees positive days ahead in its latest forecast. It predicts that global oil demand in 2018 will grow and that non-OPEC production will not increase as fast as previously thought. Along with its production cuts, that will continue to reduce excess oil in storage. OPEC, Russia, and a handful of other producers agreed to cut output by 1.8 million B/D, and compliance with the agreement has been stellar. OPEC’s report concedes that it did not kill off North American shale when it flooded the market with oil 3 years ago, and that shale will continue to see strong supply growth.
A new International Energy Agency reports confirms OPEC’s conclusion on shale’s staying power. The IEA said the supply surge in shale output will lead to the largest gains in the history of the industry. By 2025, the US will match Saudi Arabia in oil production and surpass the former Soviet Union in gas output, according to its World Energy Outlook. The US oil industry “weathered the turbulent period of lower oil prices since 2014 with remarkable fortitude,” according to the report.
Carpenter, Chris (JPT Technology Editor) | Wilson, Adam (JPT Special Publications Editor) | Rassenfoss, Stephen (JPT Emerging Technology Senior Editor) | Whitfield, Stephen (JPT Senior Staff Writer) | Donnelly, John (JPT Editor) | Boschee, Pam (JPT Senior Editor)
More than 8,300 professionals from 60 countries attended the 2017 SPE Annual Technical Conference and Exhibition, which was held in October in San Antonio, Texas. Conference panels and technical sessions examined best practices and emerging technologies throughout the oil and gas industry, including discussions on the role of data analytics, contemporary research and development initiatives, sustainability, automation, and recent innovations.
Here are highlights from this year’s conference.
Disruptive Drilling Technology
A panel on starting companies selling disruptive drilling technology began with the advice, “If you remember anything today, remember it is not about technology—it is about money.”
The advice from Tom Bates, an energy investor from Fort Worth, Texas, began a discussion put on by the Drilling Systems Automation Technical Section (DSATS) about starting successful companies that sell digitally controlled drilling tools. When discussing money, the panelists kept coming back to the critical, sometimes maddening role people play in deciding who gets money and profits in the end.
“Most profitable companies do not want things that disrupt” the status quo, said David Blacklaw, Shell global drilling automation lead. For change to happen, it may well require upper management to promote changes that have benefits that are not obvious to those in operations.
Even decision makers who see the potential are wary about changes at a time when mass layoffs are a fresh memory. “Automation has a lot of people nervous about their job security,” said Todd Benson, president and CEO of Motive Drilling Technologies. The worries range from decision makers who do not want to stake their job on an unknown startup to workers who see their jobs threatened.
Motive Drilling sells a directional drilling advisor, which offers turn-by-turn directions now delivered by directional drillers. While companies using it have continued to employ directional drillers, it changes what they do. If a worker sees something new as a job, “you are the enemy,” Benson said.
JPT publishes summaries of 144 technical papers a year, choosing from among more than 4,000 papers to ensure that it is publishing the “best of the best.” Although this has been standard practice for the magazine for years, many SPE members, as well as nonmembers, are unclear how these papers are selected.
It starts with dedicated volunteers. The JPT Editorial Committee comprises 47 oil and gas industry professionals who are experts in their field. Committee members volunteer their time to review technical papers and abstracts that have been presented at SPE conferences as well as the multisociety Offshore Technology Conference, Unconventional Resources Technology Conference, and International Petroleum Technology Conference and identify the most relevant, high-interest, and practical papers for publication. Occasionally, papers that have not been presented at a conference but submitted directly to JPT are reviewed. Reviewers also attempt to ensure that the papers represent the industry’s geographic and corporate diversity. JPT staff then summarize the chosen papers in 2–3 pages with access to the full-length paper available online. SPE members can access the full-length papers for free for 2 months at www.spe.org/jpt. Over the course of the year, JPT will publish summaries of 12–16 papers monthly in a variety of upstream areas such as hydraulic fracturing, formation evaluation, completions, and enhanced oil recovery to name a few.
The committee members have diverse positions in the industry as well as backgrounds. They include professionals at operators, service companies, national oil companies, independents, consultancies, and in academia. Qualifications to serve on the committee include SPE membership, be a recognized industry expert on a particular technical topic, have at least 10 years of experience in the oil and gas industry, and have been an author of SPE technical papers. The chair of the committee serves a 3-year term as do the committee members. Current members of the committee and their job affiliations can be found to the right of this column.
The goal of publishing these technical paper summaries is to provide readers with short versions of important papers. In years past, JPT published full-length technical papers but that allowed for publication of only a few over the course of the year. Publishing summaries allows readers to be exposed to a variety of ideas and technology applications and an avenue to easily access the full-length paper if interested. This help meets JPT’s, and SPE’s, goal of disseminating and sharing knowledge about recent state-of-the-art developments, best practices, and solutions in E&P technology.
Each reviewer also picks additional papers for a recommended reading list, for those interested in more high-quality information on a topic, and prepares an article on the state of the technology in that particular discipline. So far this year, the committee has reviewed 3,795 papers and will have reviewed more than 4,000 by the end of the calendar year.
The process is distinct, but sometimes confused, with peer review. SPE’s online technical journals publish peer-reviewed papers, which is a more lengthy process involving industry experts carefully evaluating a paper and working with the author to clarify or validate certain assumptions or statements.
In August, Mexico’s National Hydrocarbons Commission delayed the date of its next deepwater auction by a month to January 2018 to give companies more time to study the acreage on offer. Although postponing bid rounds is usually taken as a sign of lack of interest by private firms, the opposite is true in Mexico. Discoveries announced over the past few months have validated Mexico’s historic energy reform effort and may propel the oil industry there to reverse years of decline.
In a sector hampered by the downturn in oil prices, Mexico’s offshore has emerged as a bright spot. In July, US independent Talos Energy, Sierra Oil and Gas of Mexico, and Premier Oil of the UK announced one of the largest shallow-water finds of the past 20 years. The block, located off the coast of Tabasco state, holds an estimated 1.4 billion to 2.0 billion bbl of oil. The find, which came with Talos’ first exploration well, was the first since Mexico began auctioning off onshore and offshore properties in 2013. The block found up to 650 ft of oil-bearing reservoir of light crude around 28–30 °API. That same month, Italian major Eni announced the discovery of the shallowwater Amoca field in the bay of Campeche, which it said holds 1.3 billion BOE, of which 90% is oil. It is fast-tracking the development with hopes to produce from 30,000 to 50,000 B/D of 25–27 °API crude in early 2019. Consultancy PIRA Energy expects the discoveries to add up to 200,000 B/D of crude production, and believes they are economic at a $50/bbl oil price, but not for at least another decade.
Although deepwater and perhaps unconventional reserves hold the most promise for reviving Mexico’s oil sector, the country does not have a lot of time. Years of blocking the private sector out and underfunding the state oil company Pemex have taken their toll. The country’s oil and gas output is down 40% from its peak; oil production is 2.0 million B/D compared with its peak of 3.4 million B/D in 2004. That led the government to finally open the entire oil and gas sector to private money, but the reform launch could not have come at a worse time. Oil prices soon lost more than half their value, severely curtailing companies’ exploration budgets.
But the discoveries of Talos and Eni have breathed new life into Mexico’s upstream and attracted the interest of independents and supermajors. That is in contrast to the early bid rounds, which attracted only light participation. To date, seven auctions have been held—three covering onshore, three for shallow offshore, and one for deep water. Pemex has also negotiated farmout agreements with private firms. Another three are scheduled for next year. The key will be interest in the January auction. Thirty deepwater oil and gas blocks will be up for bid in areas thought to be potentially lucrative. Mexico’s deep water has been off limits to private firms and barely explored by Pemex. If resources there are anything like those found in the neighboring US Gulf of Mexico, the country’s upstream sector may become one of the globe’s offshore bright spots.
Consensus is growing around the idea that oil prices will fluctuate in the $45–60 bbl range, both in the short term and perhaps even for the long term. This has led to a rash of studies about what this means for operators and service companies in the “new normal.”
On the operator side, much of that depends on what oil price translates to profitability, both in the unconventional and conventional sectors. Some anecdotal evidence is trickling in. Public companies reported second quarter earnings in late July and early August. According to earnings reports, 15 of the largest shale producers posted total net losses of $470 million. During that time (April–June), WTI oil prices averaged $48/bbl. That was a marked improvement over the past quarter and past year. Those same companies reported total losses of $3.7 billion in the first quarter of 2017 and losses of $7.4 billion in the second quarter of 2016. The financial improvement in the second quarter came from more efficient operations, cost cutting, and a rise in oil prices.
But at what oil price are shale producers profitable? Analysts have thrown around figures of as low as $40/bbl, but a detailed study of the issue by consultancy Wood Mackenzie sheds new light on the subject and is examined on page 47 of this issue. The consensus is that $50/bbl brings most companies closer to profitability than $40/bbl, but perhaps needs to be over $50/bbl to be sustainable.
Operators are taking the “lower for longer” outlook seriously and are adapting. Occidental Petroleum announced that it was tying a company-wide compensation plan to the firm being profitable at $40/bbl. Some of the largest majors are beginning to sanction projects once again—although cautiously. More new oil and gas fields were given the green light in the first half of this year than in all of last year, including projects by ExxonMobil, Shell, and BP. But about three-fourths of those conventional projects are expansions of existing fields or satellite developments that tie back to existing pipelines and platforms, according to Wood Mackenzie. Shell, for example, is now tying its Kaikias project in the US Gulf of Mexico to its existing Ursa production hub to limit costs. When BP reported its earnings, Bob Dudley, the company’s chief executive, said the firm was planning on the basis of oil prices being at current levels for the next 5 years. Noted oil historian Daniel Yergin agreed, adding, “The industry is in the middle of re-engineering its processes and its technologies to be a $50/bbl industry, not a $100/bbl industry.”
Major oilfield services companies Halliburton, Schlumberger, and Baker Hughes reported increased revenue for the second quarter of 2017 compared with the first quarter, with revenue up 15.8% for Halliburton, 8.2% for Schlumberger, and 6.3% for Baker Hughes. Halliburton earned a slight profit while the two other companies posted net losses. Dave Lesar, chairman of Halliburton, sees a bit of a slowdown coming in shale, saying that producers were “tapping the brakes” on drilling as oil prices remain under $50/bbl and the global supply glut appears to have life left in it.
Last month, OPEC received another warning that the battle for market share in the global oil market was not over. “It’s not beneficial for OPEC to deepen their cuts because prices will go up and shale oil producers and others will take OPEC’s market share,” Abdullah al-Attiyad, the former oil minister of Qatar, said in an interview with the Bloomberg news agency. “The problem is that there is someone waiting in the dark corner for OPEC—it’s shale oil producers and whenever prices rise, they raise production.”
Al-Attiyad’s remarks came after the International Energy Agency reported that the oil market was not balancing as quickly this year as some had predicted. OPEC output rose to its highest level of the year in June and its compliance with production cuts slumped to 68%. Meanwhile, oil prices meander in the USD 45–50/bbl range and remain under pressure as US production remains strong.
The oil market has historically been an interplay between supply and demand. But a new book by a consultant and former top energy adviser to US President George W. Bush argues that oil boom-and-bust cycles are here to stay and will likely be more volatile than those in the past. Periods such as from 2004 to 2008—when oil rose to USD 147/bbl and then dropped to USD 33/bbl—or what has happened between June 2014 and the present—prices falling from USD 107/bbl to USD 26/bbl and then back to around USD 50/bbl—could be the new norm. “Recent oil fluctuations mark the return of a new and unfettered market for crude oil and, as a consequence, boom-bust oil prices are making a return after 8 decades,” Robert McNally, who is also a fellow at the Columbia University Center on Global Energy Policy, writes in his new book Crude Volatility.
Contradicting the current general consensus that US shale producers have replaced Saudi Arabia as the market’s swing producer—increasing supply as the market tightens and prices rise, and decreasing production as the market dictates—McNally argues that Saudi Arabia abandoned that stabilizing role in the mid-1980s, except for some occasional tinkering with global oil supplies in the 1990s, and shale producers are not cohesive enough to fill that role. The lack of a true swing producer explains the dramatic ups and downs of oil prices since 1998.
McNally divides oil price history into 5 eras: the severe boom-bust cycles after oil’s discovery in Pennsylvania in the late 1800s; John D. Rockefeller’s Standard Oil monopoly that enriched him but stabilized prices; the return of volatility after the Standard Oil breakup and the discovery of huge quantities of oil in Texas, Venezuela, California, and Mexico beginning in the 1920s; price stabilization by the Texas Railroad Commission from the mid-1930s to 1972; and OPEC’s attempts to control the market. But OPEC has never had sufficient spare production capacity to truly control prices, McNally believes, and non-OPEC discoveries from Alaska to the Gulf of Mexico and elsewhere have undercut the cartel’s attempts.
McNally believes that price swings in the range of USD 30/bbl to USD 100/bbl may be likely, playing havoc with governments that depend on oil revenues and companies trying to plan expensive projects. Oil cycle volatility is caused by basic economics—imbalance in supply and demand, which fuels price swings, which causes further sup-ply fluctuations. And because the industry is often surprised—whether it be the sharp growth in Asian demand in the early 2000s or the recent incredible growth in shale production in the US—it will be impossible to stabilize prices in the short term.
Several recent studies have shown that there is no evidence that hydraulic fracturing in unconventional plays harms groundwater. These reports follow a very detailed 5-year study released earlier this year by the US Environmental Protection Agency (EPA) that found no “widespread impact” but was cautious in its conclusions.
In April, results from a 3-year study conducted by Duke University, Ohio State University, Penn State, Stanford University, and the French Geological Survey concluded that unconventional oil and gas extraction using hydraulic fracturing and horizontal drilling caused no groundwater contamination in five Northern Appalachian Basin counties in West Virginia. The study monitored water wells both before and after the installation of shale gas wells. The authors observed: “[Our report] provides a clear indication for the lack of groundwater contamination and subsurface impact from shale gas drilling and hydraulic fracturing. Saline groundwater was ubiquitous throughout the study area before and after shale gas development, and the groundwater geochemistry in this study was consistent with historical data reported in the 1980s.”
But the study also concluded that accidental spills of waste water from fracturing could threaten surface water in the region. The peer-reviewed study, which was published in the European journal Geochimica et Cosmochimica Acta, showed that methane and saline groundwater were found in some samples, but they occurred naturally in the region’s shallow aquifers and were not caused by shale activity.
Similarly, in late May the US Geological Survey released its findings after studying the impact of unconventional activity in parts of Louisiana, Arkansas, and Texas. Included in the study were the prolific production areas covering the Eagle Ford, Haynesville, and Fayetteville formations. That study concluded that unconventional oil and gas production in those areas is not a significant source of methane or benzene in drinking water wells.
This was the first study to determine the presence of those chemicals in drinking water wells in relation to the age of the groundwater. “Understanding the occurrence of methane and benzene in groundwater in the context of groundwater age is useful because it allows us to assess whether the hydrocarbons were from surface or subsurface sources,” the study said. “The ages indicated groundwater moves relatively slowly in these aquifers. Decades or longer may be needed to fully assess the effects of unconventional oil and gas production activities on the quality of groundwater used for drinking water.”
The 5-year EPA study was an update of a 2015 study that concluded that no harm to groundwater had been done by shale activity. The new study is more cautious, saying that hydraulic fracturing can contaminate water “under some circumstances.” But it said that the incidents that had occurred had been few, especially compared with the number of wells it studied.
Controversy surrounding these studies and their conclusions will continue. Additional studies are under way examining not only fracturing’s potential impact on groundwater, but on methane releases and seismic activity. And the resiliency of US unconventional activity during the price downturn indicates that this sector is here to stay.
Public and government concern over unconventional oil and gas production continues. Hardly a month goes by before another study into the potential health effects of shale production is launched or a public hearing is conducted regarding the impact of a project on the local landscape.
For example, last month the Southwest Pennsylvania Environmental Health Project opened a public health registry to track and analyze the impact of shale gas development on people living near wells, pipelines, and other infrastructure. That followed the release of a Duke University study that concluded that hydraulic fracturing in the Marcellus Shale did not pollute groundwater in West Virginia but that wastewater spillage contaminated some surface water. Many of the reports and studies are drawing similar conclusions—that hydraulic fracturing poses little or no risk but that contamination can occur during the transportation or treatment process.
Shale oil and gas development has certainly changed the world order in these commodities, from OPEC strategy and commodity prices to global import/export patterns. The US, with abundant gas still depressing prices, is becoming an exporter of liquefied natural gas rather than an importer. Shale oil is largely responsible for the low oil prices of the past 2 years, turning the US into the world’s “swing” producer, a position Saudi Arabia once held. Industry resiliency amid low oil prices led to slashing of service company costs, operational efficiencies, and high-grading of properties. As service costs now begin to rise, profitable production in a world of USD 40–60/bbl oil will require further innovation.
But the industry also continues to face regulatory challenges based on environmental concerns. Maryland has recently followed New York in legislating against hydraulic fracturing. A new book, Sustainable Shale Oil and Gas: Analytical Chemistry, Geochemistry, and Biochemistry Methods by Vikram Rao and Rob Knight argues that this type of policymaking is hampered by inadequate data, which in turn is caused by shortcomings in analytical techniques. The authors describe new cost-effective analytical methods for detecting fugitive methane as well as particulate matter and volatile organic chemicals, including a portable shoe-box-sized mass spectrometer with performance approaching that of a laboratory machine.
The last line of the book states, “That which cannot be measured, cannot be regulated or otherwise controlled or exploited.” They apply this reasoning to improving the economics of recovery as well. The book discusses analytical methods to illuminate the unconventional reservoir, including a fascinating method using DNA sequencing to characterize reservoir rock through examination of microbial populations.
The book lays out how analytical chemistry, geochemistry, and biochemistry play prominent roles in hydraulic fracturing and that they are central to the three tenets of sustainable production: protecting the environment, protecting the well-being of local communities, and profitability.
Innovation has been a necessity for survival in the low oil and gas price market, and continued innovation will result in an industry resilient to future unexpected challenges. And the authors contend that that innovation and production is achievable in environmentally responsible fashion.
Momentum is building for what is being called the “peak demand” theory—that before too long global oil demand will begin to fall as transportation efficiency, innovations such as electric cars, and government climate change policies will quell the rising consumption of hydrocarbons that has marked the past several decades. What is getting attention is that this sentiment is no longer coming from what could be termed anti-oil interests but is coming from the likes of Shell’s chief executive officer (CEO) and such organizations as the World Energy Council (WEC).
Speaking at an energy conference in Houston in March, Shell CEO Ben van Beurden predicted that world oil demand could peak in the late 2020s because of the growth of renewable energy sources and natural gas. He noted that his company is moving toward a lower-carbon, long-term strategy. Shell recently divested most of its Canadian oil sands position and is increasing its position in natural gas. Last year, it bought the BG Group, which built up its natural gas portfolio. Van Beurden emphasized that the industry must reduce carbon dioxide emissions to help countries meet the recent Paris climate change accord goals.
The WEC has predicted that global energy consumption will begin declining in a little over a decade, and its eighth annual survey of energy executives around the world showed that growth in renewables and energy efficiency is requiring firms to revise their medium- and long-term outlooks.
The peak demand theory undercuts the prevailing industry notion that a rising middle class in developing countries will propel oil demand much higher. Just a few years ago, the industry and many economists were fretting about a shortage of energy supplies to meet this growing consumption. At the same conference where Shell’s CEO spoke, the head of the International Energy Agency (IEA), Fatih Birol, said that global demand is not peaking and in fact will grow by 7.3 million B/D through 2022. He pleaded with oil companies to invest more, otherwise the world would face an oil shortage in the future and the prospect of huge price spikes. He noted that even though sales of electric cars had risen to a record number of more than 1 million, this was still less than 1% of total global auto sales. The trucking, airline, and chemical sectors will continue to drive oil growth, he said.
In general, the oil industry is not good at predicting the future. The oil price decline in the late 1990s, the huge run-up in prices led by surging Chinese and Indian demand in the early 2000s, the strength of the price collapse of the past 2 years, and the resilience of the US shale sector all seemed to catch much of the industry flat-footed. The growth in unconventional production has only made supply/demand forecasts tougher.
The argument might not be so much about peak demand, but about timing. The industry as well as organizations such as the IEA have predicted that global hydrocarbon use would decline this century and that natural gas would be the “bridge to the future” of economies built more around renewable energy sources. The question is whether that will come in 15 years, 30 years, or even longer.