Rig Count Research Articles

The Asymmetric Relationship between Conventional/Shale Rig Counts and WTI Oil Prices

This work analyses the asymmetric response of conventional and shale oil rig counts to WTI oil price returns. Our analysis shows that the rig count time series exhibited a structural change after the oil glut of 2014. All series are non-stationary in each sub-period but not cointegrated. Therefore, after controlling for possible confounding factors, a vector auto regressive (VAR) model is set up. Our specification accounts for the possible role of oil production and distinguishes between positive and negative oil price changes. It is shown that shale and conventional rig counts reacted differently in each subperiod to signed changes in oil price. Subsequently, by evaluating the response of rig counts to oil price shocks, their intensity and duration over time, we observe that the shale oil rig count reacts more intensively to positive than to negative oil price changes. On the contrary, the conventional rig count exhibits a modest reaction only to positive price changes. Finally, we robustify our findings by focusing on the data of the Permian basin, on the one hand, and the Anadarko, Bakken, Eagle Ford and Niobrara, on the other hand, which are characterized by different patterns in the number of Drilled but not Completed wells.

Revisiting WTI–Brent spread and its drivers

We made two key contributions to energy economics and finance by revealing new insights on the WTI–Brent spread (WBS). Our first exercise engages with the stylized facts of the WBS and its role as an indicator, identifying the time around the shale oil revolution as a turning point in the mean- and persistence-based shifts in the spread's time-series properties. The second exercise delves into the fundamental connection between the WBS and key US-based and international market factors. We utilized three sets of explanatory factors, representing demand, supply, and uncertainties. The data for this study were sourced primarily from Refinitiv Eikon and EIA, spanning from 1988 to 2020. The results affirmed demand-side variables to have predictive power for widening spreads, whereas supply-side factors, such as oil rig counts, trans-US pipeline flow, and import from Canada, contributed to spread shrinkage. This finding specifically held in robustness check using quantile-based regression. Supplementary causality tests revealed that economic conditions contain greater causal influence than market-based indicators, suggesting that the spread traders respond more to fundamental drivers than financial sentiments.

Asymmetric Effects of Prices and Storage on Rig Counts: Evidence from the US Natural Gas and Crude Oil Markets

This study empirically investigates the asymmetric effects of spot (future) prices and storage on rig counts in the US natural gas and crude oil markets from January 1986 to May 2020. It adopts the Nonlinear Autoregressive Distributed Lag (NARDL) model and establishes a flexible and efficient framework that measures the effects of positive and negative shocks in each of these variables on rig counts while modeling possible asymmetries in both the short and long term. For the natural gas market, the results reveal significant long-term asymmetric effects of spot (future) gas prices and storage on gas rigs. The positive and statistically significant cumulative effect of changes in natural gas storage suggests that larger natural gas storage has caused changes in the use of natural gas drilling rigs. For the crude oil market, we find significant short-term asymmetric effects of spot (future) gas prices and oil stocks on oil rigs. Furthermore, in addition to the optimal price and level of storage, the cost, as proxied by the interest rate, is a crucial determinant in rig drilling decision-making in the energy sector.

Technology Focus: Drilling Automation and Innovation (February 2023)

With the arrival of the digital age, solutions in big data, automation, and artificial intelligence are rapidly opening the door to a deeper and more-comprehensive understanding of drilling operations around the world. The exponential growth in data acquisition, modeling, and prediction capabilities allows multiple drilling teams to identify hidden patterns and correlations to deal with the most-complicated challenges in well construction. In related SPE papers, it was interesting to read about promising initiatives undertaken by operators, service companies, and academia, not only to recognize details on past drilling events but also to accurately simulate, anticipate, and automate complex situations. Topics such as machine learning for improved decision-making, equipment-failure prediction, well placement lookahead, and autonomous operations have attracted great interest from the industry. Therefore, demand for a skilled workforce in digital technologies will continue to grow in drilling-related disciplines and new information and technology work flows will be incorporated into the well life cycle. As the active rig count continues to increase, safety must remain top priority for drilling operations. Advances in digital technologies and automation contribute to this objective while keeping a focus on cost management, operational consistency, and carbon-footprint reduction. Ongoing actions will also help to accelerate the development of geothermal energy as part of the future mix of renewables. The selected papers highlight some interesting contributions to drive innovation and promote efficient use of processes and technologies. Recommended additional reading at OnePetro: www.onepetro.org. SPE 205899 Measurements During Drilling Through an Innovative Microchip Technology To Determine Accurate Wellbore Properties for Efficient Drilling Operations by Zuyang Zhu, Sinopec, et al. SPE 211791 A Novel Real-Time Well-Collision Avoidance Monitoring by Definitive Dynamic Surveys and Passive Magnetic Ranging by Mahmoud ElGizawy, SLB, et al. SPE 210306 Drilling Heat Maps for Active Temperature Management in Geothermal Wells by Mohamed Shafik Khaled, The University of Texas at Austin, et al.

Comments: What’s Holding Back Production Increases?

The big oil producers are balancing the chasing of more production with delivering dividends to shareholders. So far, the scale is tipping in favor of shareholders. While recent quarterly reports have made this clear, it was reemphasized at a US House Energy and Commerce Committee hearing in April when executives from Chevron, BP America, Devon Energy, ExxonMobil, Pioneer Natural Resources, and Shell USA addressed alleged “price gouging” at the gas pump and rejected pressure to shift their record profits from paying dividends and stock buybacks to ramp up production and lower prices. The executives’ statements ranged from “We can increase production and return value to our shareholders” (Chevron CEO Michael Wirth) to Devon Energy CEO Richard Muncrief and Pioneer Natural Resources CEO Scott Sheffield stating “the answer is no” when asked if they would reduce buybacks and dividends. Gretchen Watkins, Shell USA president, said her company intends to make investor returns and increase production and investments in renewable energy. Several of the executives pointed to their industry’s record losses during the pandemic when demand tanked (global fuel consumption fell by more than 25%) and West Texas Intermediate fell off a cliff to –$40/bbl on 20 April 2020 and slowly crept up. Even if the oil price drops, retail gas prices won’t immediately follow to stem the allegations of price gouging. Garrett Golding, a senior business economist at the Federal Reserve Bank of Dallas, wrote, “In the energy economics world, this phenomenon is known as ‘rockets and feathers,’ where it is commonly observed that prices at the pump shoot up with oil prices like a rocket, but fall like a feather back to the ground after oil prices drop. There are two reasons for this scenario repeating itself during oil-price spikes: the macro-level logistics of how oil and refined products churn through the physical market and the micro-level economic decisions of service station owners and their customers.” Today, demand is strong even at average oil prices of about $103/bbl over the past 6 weeks. Now, the summer driving season is around the corner and consumers are eager to hit the road and fly the skies, finally free(r) of pandemic restrictions and concerns. Yet, the Permian rig count has remained fairly flat over the same period. Despite high oil prices (WTI just below $114/bbl on 17 May), drillers aren’t ramping up activity. Many interrelated factors affect supply and demand. Simplifying the complexity of the global market shines, at best, a narrow beam on some of the factors affecting production. The supply side is dealing with volatility of oil prices; the uncertainty of Europe’s energy supplies, including Europe’s potential embargo on Russian oil; the varied focus on energy transition; sustained fiscal restraint by smaller operators as they continue to reduce or avoid debt; the shortage of sand needed for fracturing in the North American shale plays; labor shortages; the reactivation of idled equipment; and supply chain disruptions. A supply bottleneck is affecting oil country tubular goods (OCTG), which have seen volatility related to the “weak domestic demand in China due to COVID-19 lockdowns and Chinese currency depreciation,” wrote Rystad senior analyst Marina Bozkurt in a recent market note. Business activity has been affected by shutdowns and logistics problems. “OCTG prices may remain pretty high this year, driven by higher costs of raw materials due to geopolitical tensions globally and government regulations to reduce carbon emissions.” Prices continue to increase at Japanese OCTG mills, where the focus is primarily on value-added products such as 13Cr material. Propping up prices are “tight global availability and strong demand. Despite a possible price fluctuation for raw materials, prices will unlikely cool down significantly as long as the Russia-Ukraine situation continues.” In an April report, the Federal Reserve Bank of Dallas said the growing gap between OPEC+ production quotas and actual oil production is being driven by production capacity constraints in several OPEC+ countries, largely attributable to Angola, Nigeria, and Saudi Arabia. Their capacity is limited by “infrastructure issues and the difficulty of attracting sufficient investment to offset production declines at existing wells.” The shortfall was nearly 1.1 million B/D in February, the most recent month for which there were official production data available. In May, JP Morgan lowered its outlook for 2022 global oil demand by 1 million B/D, citing higher oil prices, a weakening growth outlook, and escalating geopolitical tensions. How this plays out will affect producers’ appetite to increase or decrease their production or reconsider their priorities.

Shale revolution, oil and gas prices, and drilling activities in the United States

We investigate the interplay between energy prices and drilling activities in the United States and how this relationship has evolved due to the shale revolution. We hypothesize that (1) there exists significant information spillover between drilling activities and energy prices; (2) the amount of information transmitted between drilling activities and energy prices has increased since the shale boom; (3) natural gas market is increasingly important information transmitter since the rise of unconventional oil and gas production. Using connectedness indexes constructed based on vector autoregressive models and data from 1997 to 2019, we find support for all three hypotheses. In particular, the linkage between drilling activities, measured by active rotary rigs in operation, and oil and gas prices in the US has strengthened since 2012. Oil and gas drilling activities have become more responsive to price variations during the shale revolution. However, the information transmitted from oil prices to rig count declined when oil prices fluctuated in a relatively stable range toward the end of the sample period. In contrast, the information transmitted from gas prices to gas rig counts has increased during the same time frame.

The Asymmetric Relationship between Conventional/Shale Rig Counts and Wti Oil Prices

The Asymmetric Relationship between Conventional/Shale Rig Counts and Wti Oil Prices

Economic growth and crude oil revenue in Nigeria

This paper investigated how oil revenue and the activities in the oil industry affected the size of income accrue to each Nigerian (Per capita income) from 1980 to 2019. The variables were sourced from the World Bank’s World Development Indicators (WDI), OPEC Statistics, Baker Hughes Rig Count and the central bank of Nigeria statistical bulletin. Using the AutoRegressive Distributional Lag (ARDL) we observed that explorative activities of crude oil in Nigeria positively impacted the size of individual income. The magnitude of the impact was massive irrespective of time; a 1% increase in exploration increases the size of individual income by 0.4786% in the long run and 0.6030% in the short run. The interaction of rigs by output (interaction of rig-count and oil-production) negatively impacted the size of individual income. This implies that the size of individual income in Nigeria is sensitive to the nature of the explorative environment of the Nigerian oil industry.

Econometric analysis of factors influencing commercial helicopter operators’ stock returns in the gulf of Mexico

Commercial helicopter services in the oil and gas industry play a vital role in transporting crews and supplies to offshore installations. There has been ample research analyzing the impacts of fluctuating crude oil and natural gas prices on regional economies, energy service firms and upstream, downstream and integrated energy firms. However, the extent to which commercial helicopter operators' stock returns are related to commodity prices and other relevant industry variables is absent. Often, firms attribute favorable financial results to internal factors whereas unfavorable financial results are attributed to external factors. Commodity prices have exhibited a negative relationship with airlines and other transportation firms due to the input price of fuel whereas demand for helicopter services is hypothesized to be positively related to crude oil and natural gas prices. In order to determine the contributing factors related to firms' stock returns, empirical analyses are required, and conducted in this paper. Using a unique data set from 2013 to 2018, this paper presents research which identifies structural relationships between crude oil prices, natural gas prices, the rotary rig count, a subset of the overall market and stock returns of commercial helicopter operators, which is a unique addition to the extant literature and provides researchers and practitioners foundational knowledge for future research inquiries and operational and investment decision making, respectively. Empirical analyses show that 10% increases in the crude oil price and the S&P 500 index yield a 2.7% and 8.0% increase in stock returns, ceteris paribus. Crude oil price risk may be increasingly prevalent as societies promote renewable energy sources. Furthermore, we present foundational knowledge that promotes further research and knowledge representing a caveat to traditional relationships between commodity prices and transportation firms’ financial performance.

All the DUCs in a Row: Natural Gas Production in U.S.

Using data from seven shale gas regions in the United States, we examine natural gas production in terms of drilling rig activity and well completion rates. Our objective is to examine the determinants of well completion decisions in the U.S. natural gas production. We observe that in recent years, the explanatory power of drilling rig count has declined. On the other hand, the number of producing wells remains a significant factor for explaining the variation in gas production. We find that an increase in the number of drilled but uncompleted wells (DUCs) plays a significant role in natural gas supply. The number of DUCs depends on drilling rig activity and futures prices of oil and natural gas. Also, our results indicate that well completion decisions and the duration of DUC status depend on oil and gas prices, pipeline capacity, producing well type and well depth.

Efficient estimation in semiparametric self-exciting threshold INAR processes

This paper focuses on the efficient estimation problem of a more realistic semiparametric SETINAR model of order one with two regimes based on binomial thinning operator. Unlike parametric framework, we do not suppose that the distribution of the innovation process belongs to a parametric family. Instead, the innovation distribution is totally unspecified and is supposed to satisfy only some mild technical assumptions. We, therefore, provide efficient estimators for both parameters of the model, namely a vector of auto-regression parameters and the innovation distribution which is considered as a parameter of infinite-dimension. The performances of these efficient estimators are shown through an intensive simulation study and an application on rotary rig count data in the U.S.A.

Technology Focus: High-Pressure/High-Temperature (March 2021)

For the past several months, the rig count in North America has been slowly but steadily improving and some pockets of deepwater operations are finally showing some activity, especially in Central and South America and Africa, where interesting discoveries continue. Arctic operations also are picking up, though not in North America, where a new administration in the US is bringing some uncertainty to upstream operations. Looking at leasing activity in 2020, however, the operators on federal land seem to have built up a backlog, so the immediate consequences of recent executive action seem not to be significant, though they do set an important precedent. More significant seems to be the opposition to pipelines, which are the most-efficient and safest way to transport any form of bulk material, be it gas, liquid, or slurry. Even if the most-stretched targets of an energy transition become reality, the need for pipeline transport will remain, and even increase, if the gas transported is biogas and hydrogen, where much larger volumes must be transported for the same calorific value of natural gas. In my tenure as a reviewer for JPT, I had refrained from a materials-focused special simply because high-pressure/high-temperature (HP/HT) conferences and sessions seem to be dominated by them and I wanted to demonstrate a wider spectrum of the challenges of HP/HT operations. With the energy transition leading to the possibility of free hydrogen being introduced into the energy system outside of established chemical feedstock installations (which are all low-pressure), this is a good time to remind our industry (and the outside world) that vast experience exists in the oil and gas industry on the interaction of hydrogen and metal (at very high pressures), a challenge that is still not completely understood and that is still a large cause of pressure-vessel failures (e.g., in refineries). Also, if carbon dioxide is intended to be captured and contained in metal vessels, another set of metallurgical challenges emerges. This Technology Focus looks at two papers from Asia, where these challenges were discovered and mitigated, and one paper from Gulf of Mexico deepwater operations. Many learnings can be taken from these papers, and extremely costly and safety-critical failures and loss of containment can be avoided. Addressing technical risk, thorough and detailed front-end engineering is a cost-effective and cost-saving activity, and this applies especially for front-end corrosion engineering and testing, as we have seen from several megaprojects in the past where this was not done to the extent finally understood to have been required. So, I invite you all to understand and embrace the fact that sound and competent engineering, as well as communicating learnings across functions and industries, is the key enabler for future success in our stressed industry, and to use our engineering brainpower and imagination to bring those HP/HT projects currently deemed too expensive to develop within the realm of the current oil-price environment.

Comments: Oilfield Services Face Low and Slow Recovery

OPEC’s easing of production cuts originally planned for January may be delayed until mid-2021 because of the global increases in COVID-19 cases occurring in November. As restrictions are renewed, extended, or newly instated, fuel demand is expected to decrease. Following a Joint Technical Committee (JTC) meeting on 16 November, OPEC Secretary General Mohammed Sanusi Barkindo underscored the need to remain “vigilant and diligent” in the months ahead. The JTC recommended that supply increases be postponed from 3 to 6 months. The OPEC ministers plan to hold an online meeting on 30 November to decide on production levels among the 13 member countries. By the time you read this in early December, their decisions - and the market responses to them - will be evident. Approximately 7.7 million B/D, or about 8% of global production, are currently tamped down. The recent encouraging announcements of two vaccines’ effectiveness in early clinical trials buoyed oil prices, which are hovering around $40/bbl (West Texas Intermediate closed at $41.38 on 16 November). The past 8 months brought with them upheavals in operators’ and service companies’ short-term reactions to market conditions based on their financial resiliency, and as the pandemic persists, the fallout sputters on as layoffs, bankruptcy filings, mergers and acquisitions, and new collaborative business deals arise almost daily. One sector thought to have bottomed out globally is oilfield services (OFS) and drilling, according to Moody’s Investors Service’s outlook published 13 November. Improvement in earnings is expected to be slow in 2021 as a result of the limited growth forecast in development activities and capital investment. Low and slow growth may be the sector’s motto for some time. The record lows in the third quarter of this year in the drilling rig count and well completion/servicing activity hit the OFS hard after operators reined in capital spending. Some recovery in the US has occurred since August when the rig count tanked at 244. By late October, it neared 300. The international rig count drop has slowed and reached fewer than 700 by later October. Moody’s reported the decrease will continue, but at a slower rate, through the end of this year.

Technology Focus: Gas Production (November 2020)

When two black swans - weak industry fundamentals and a global pandemic - collided midair, a downward spiral became a freefall. Accompanied by the human tragedy of illness and financial hardship, industry employment shrunk at a pace not seen since 1986 and caused a contraction to the lowest international rig count since Baker Hughes started keeping records 43 years ago. How has this upheaval affected the demand for the natural gas our industry supplies? Not very much. Essential goods and services rose to the top of our attention in 2020, and natural gas has proved to be essential and reliable. Gas-fired electricity usage actually increased as stay-at-home orders nullified the economies of scale provided by shared workspaces. Natural-gas-powered delivery trucks bring things to us as we avoid crowded stores. While office buildings are kept cool or warm for a small number of onsite workers, work-from-home employees now demand a comfortable home 24 hours a day rather than just evenings and weekends. Worldwide demand is marginally lower because of curtailed economic activity, but that decline has been matched by the decrease in associated gas from shut-in oil wells. While the selected papers were written before these developments, they each show the spirit of innovation and dedication to improving processes that will be required to rebound fully and continue to deliver the energy our world needs. Engineers thrive on making more from less, and this month’s paper selections highlight efforts to improve the efficiency of gas-production operations throughout the world. Natural-gas suppliers continue to provide uninterrupted service despite fewer people and smaller budgets. Like other essential workers, they are heroes and deserve our sincerest thanks.

Does the Hashrate Affect the Bitcoin Price?

This paper investigates the relationship between the bitcoin price and the hashrate by disentangling the effects of the energy efficiency of the bitcoin mining equipment, bitcoin halving, and of structural breaks on the price dynamics. For this purpose, we propose a methodology based on exponential smoothing to model the dynamics of the Bitcoin network energy efficiency. We consider either directly the hashrate or the bitcoin cost-of-production model (CPM) as a proxy for the hashrate, to take any nonlinearity into account. In the first examined subsample (01/08/2016–04/12/2017), the hashrate and the CPMs were never significant, while a significant cointegration relationship was found in the second subsample (11/12/2017–24/02/2020). The empirical evidence shows that it is better to consider the hashrate directly rather than its proxy represented by the CPM when modeling its relationship with the bitcoin price. Moreover, the causality is always unidirectional going from the bitcoin price to the hashrate (or its proxies), with lags ranging from one week up to six weeks later. These findings are consistent with a large literature in energy economics, which showed that oil and gas returns affect the purchase of the drilling rigs with a delay of up to three months, whereas the impact of changes in the rig count on oil and gas returns is limited or not significant.

Rethinking Exploration

“Down but not out” is how Westwood Global Energy Group described exploration drilling in an article based on its State of Exploration 2020 Report. The Baker Hughes rig count provides supporting details. On 12 May, the data showed 339 active rigs in the United States - the lowest level since the rig count was introduced in 1987. On 1 June, the US count plunged to 301 in its 12th week of losses. At the worst of the 2014-2016 oil bust - the previous lowest point on record - 404 rigs were operating. The worldwide rig count for May was 1,176, down 338 from the 1,514 counted in April and down 1,006 from the 2,182 counted in May 2019. And, Rystad predicted on 28 May that more than half of the world’s planned licensing rounds for 2020 are likely to be canceled. The consensus among industry experts is that exploration will be hit by some of the deepest cuts inflicted by the coronavirus pandemic, the biggest oil market crash in history, and the transition to a low-carbon energy future. The silver lining is that there is still a business case for exploration despite these difficult times. Julie Wilson, director of global exploration research for Wood Mackenzie, said in a recent virtual panel discussion that the role of exploration in replacing supply sources in current portfolios with “new and better” barrels of oil equivalent (BOE) will continue over the next 20 years. But for explorers to prosper, those barrels will need to be low in cost and emissions. Rude Awakening For the exploration sector, 2020 began with a degree of cautious optimism and increasing activity. Confidence had returned with improved performance, the highest commercial success rate (CSR) in 10 years, and the discovery in 2019 of several multi-billion-barrel plays. Explorers were keenly aware of challenges ahead, including investability, capital efficiency, the risks of exploring in deep water, and societal pressure to move toward energy transition. But, the overall outlook was for another 30 years of profitable exploration. At the start of the year, the high-impact well count had been expected to be similar or slightly higher than the 93 wells completed in 2019. Westwood now expects around 60 to 70 high-impact exploration wells to be completed by the end of 2020, a decline of up to 35% and back to the numbers and volumes seen from 2016 to 2018 following the 2014 oil price crash. In the Gulf of Mexico (GOM), the number of executed high-impact wells has declined from 34 to 15, all in deep water. Seven of those have been spudded. For independent GOM explorers, the number of expected wells went from 13 to one, as companies decided to focus their bare-minimum budgets on near-term production.

E&P Notes (June 2020)

E&P Notes (June 2020)

Does the Hashrate Affect the Bitcoin Price?

This paper investigates the relationship between the bitcoin price and the hashrate by disentangling the effects of the energy efficiency of the bitcoin mining equipment, bitcoin halving, and of structural breaks on the price dynamics. For this purpose, we propose a methodology based on exponential smoothing to model the dynamics of the Bitcoin network energy efficiency. We consider either directly the hashrate or the bitcoin cost-of-production model (CPM) as a proxy for the hashrate, to take any nonlinearity into account. In the first examined sub-sample (01/08/2016-04/12/2017), the hashrate and the CPMs were never significant, while a significant cointegration relationship was found in the second sub-sample (11/12/2017-24/02/2020). The empirical evidence shows that it is better to consider the hashrate directly rather than its proxy represented by the CPM when modeling its relationship with the bitcoin price. Moreover, the causality is always uni-directional going from the bitcoin price to the hashrate (or its proxies), with lags ranging from 1 week up to 6 weeks later. These findings are consistent with a large literature in energy economics, which showed that oil and gas returns affect the purchase of the drilling rigs with a delay of up to 3 months, whereas the impact of changes in the rig count on oil and gas returns is limited or not significant.

Comments: A Year of Uncertainty

Editor's column Late December/early January is the time of year when industry outlooks are announced, revealing company spending plans, oil price predictions, and potential stumbling blocks. The steep drop in prices in the fourth quarter of 2018 made these outlooks particularly challenging, and most are laced with cautious optimism about the year ahead. But common themes emerge: the industry is still in cost-containment recovery mode; the march toward digitalization is in full swing; and shale output from the US will only increase as pipeline bottlenecks began to ease with new construction. This past year was one of recovery, as the downturn that began with the price crash in 2014 appeared to be over, although that view is not unanimous. Capital expenditures rose last year because of higher oil prices but spending was cautious, and that caution was validated when both Brent and WTI prices fell about $30/bbl during the fourth quarter. A price rally in January began to ease concerns that the industry was in another free fall. Oil and gas spending growth rose 4% in 2017 and 5% in 2018, according to the International Energy Agency (IEA), after dropping 60% during 2014–16. The US shale sector contributed largely to that growth, as spending on unconventionals outstripped interest in conventional oil and offshore. Majors increased their visibility in unconventionals in plays such as the Permian Basin. Shale remains a bright spot, and will allow the US to likely remain the world’s largest producer of liquids and gas. Global oil inventories have come down significantly since the downturn, even with the increase in US production. But major uncertainties exist, making this year “even more hazardous than usual” to forecast trends in 2019, an IEA spokesman was quoted as saying. That uncertainty is reflected in a recent survey of more than 30 oil analysts, who predicted that Brent prices would end the year anywhere from $30/bbl to $78/bbl. Deloitte’s 2019 industry outlook states that “opportunities from digital technologies are becoming increasingly apparent and have the potential to unlock new value.” As featured in JPT over the past year in particular, more companies are employing or experimenting with artificial intelligence, automation, machine learning, robotics, and blockchain, often attracting nontraditional vendors and startups. The offshore sector has yet to recover. US Gulf of Mexico (GOM) production rose last year but drilling activity did not, and the rig count ended the year at an 81% utilization rate. There were 36 active deepwater GOM sites at the end of the year, compared with 49 in early 2017, according to the US Bureau of Safety and Environmental Enforcement. Norway’s upstream regulator is not optimistic about spending there. Oil and gas production will fall 4.7% this year to 1.42 million B/D after a 6% drop last year, according to an annual report by the Norwegian Petroleum Directorate. Mexico’s offshore may be a bright spot, but the industry is still looking for signals from the new government that it is friendly toward private sector E&P.

E&P Notes (October 2018)

E&P Notes Equinor To Employ Permanent Reservoir Monitoring at Arctic, North Sea Fields Matt Zborowski, Technology Writer Equinor will use permanent reservoir monitoring (PRM) to help improve recovery in two of the operator’s more important offshore projects of the next few years. The Norwegian state-owned operator has exercised an option in an existing framework agreement with Alcatel Submarine Networks (ASN) to implement the technology at its Johan Castberg field in the Barents Sea. That framework agreement was reached in January for PRM deployment at the Johan Sverdrup field in the North Sea. The technology involves the permanent installation of seismic sensors on the seabed, enabling the operator to continually monitor reservoir changes—with better images—throughout the lifespan of a field. Equinor said the information generated from PRM will aid its overall efforts in visualization, modeling, and, eventually, predictive analyses. Directional Drilling Services Market Grows in 2017, Near-Term Upward Trend Expected Stephen Whitfield, Senior Staff Writer A new report from Spears & Associates paints a positive picture for the global directional drilling services market as it recovers from the oil-price down-turn. After falling from $16.5 billion in 2014 to $7.1 billion in 2016, market growth is projected to accelerate in the near term. The directional drilling services market grew 16% in 2017 as increased horizontal drilling activity in the US and longer per-well lateral length offset a faster penetration rate. Richard Spears, vice president of Spears & Associates, said that lateral length has created an enormous demand for directional drilling services even though rig counts are still not high. “It doesn’t even matter that much what the drilling rig count is,” Spears said. “The question is how many feet are being drilled in the horizontal section? That’s the only metric that matters. If I’m drilling 10,000-ft laterals and 12,000-ft laterals and 20,000-ft laterals, that just means there’s a greater intensity of use for directional drilling services every day, every quarter.” Bids, Dollars Rise in Third Regionwide US Gulf of Mexico Lease Sale Matt Zborowski, Technology Writer The third regionwide US Gulf of Mexico lease sale drew more bids and more money than the first two, providing, for now, another reason for optimism in an offshore industry hungry for a resurgence. Lease Sale 251 drew 171 bids on 141 blocks with high bids totaling $178.1 million, up 43% from the last regionwide auction in March, the US Bureau of Ocean Energy Management (BOEM) announced from New Orleans on 15 August. Twenty-nine companies submitted bids, including the usual group of participants consisting of majors and big independents from past lease sales. Offshore operators showed “their continued confidence in the region,” said William Turner, senior research analyst at Wood Mackenzie, in comments following the event. The improved results came in spite of less acreage being made available compared with the March auction—the largest ever—and the government’s unwillingness to budge on recommended cuts to offshore royalties. Diamondback Energy Spending $10.5 Billion in Permian Acreage Expansion Matt Zborowski, Technology Writer Diamondback Energy Inc. is amassing billions of dollars’ worth of Permian basin acreage in a pair of deals that rivals recent acquisitions by BP and Concho Resources. In the biggest, reported 14 August, Diamondback agreed to acquire Energen Corp. in an all-stock deal valued at $9.2 billion, including Energen’s net debt of $830 million. A week earlier, Diamondback said it agreed to buy Ajax Resources for $1.25 billion. The deals will give Diamondback 390,000 net acres across the Midland and Delaware Basins, up 85% from 211,000 net acres as of 30 June. This includes 266,000 net “tier one” acres and 7,000 estimated total net horizontal locations, the company said in a statement.