US Energy Information Administration Research Articles

Medhat M. Kamal 2023 SPE President

Medhat (Med) M. Kamal Medhat (Med) M. Kamal is a Chevron Fellow Emeritus and an Honorary Member of SPE. He previously worked for Cairo University, Amoco Production Company, Flopetrol Schlumberger, and ARCO Exploration and Production Company. Kamal has more than 45 years of industry experience in well testing, reservoir description, and production and reservoir engineering. He was an SPE Distinguished Lecturer in 1997–1998 and 2018–2019 during which he presented his lectures more than 80 times in 35 countries. He served as a member and chairman of SPE Annual Meeting Well Testing subcommittee and textbook and monograph committees, and as executive editor, associate editor, and technical reviewer for SPE Reservoir Evaluation & Engineering and the Journal of Petroleum Technology. He chaired the first SPE conference on research and development in 2007 and the Western Regional Meeting (2019). He served on the boards of directors of Mid-Continent, Gulf Coast, Dallas, and Golden Gate sections of SPE and chaired the Dallas and Golden Gate sections. He also served on the SPE International Board of Directors (2007–2009) as the Regional Director of Western North America. Kamal has been recognized with several regional and international awards including the SPE Cedric K. Ferguson Medal, SPE Formation Evaluation Award, SPE Distinguished Service Award, SPE North and East Texas Regional Service Award, and the Texas Petroleum Engineer of the Year Award. He holds a BSc in petroleum engineering and an MSc in engineering from Cairo University and an MS and PhD in petroleum engineering with a minor in computer science from Stanford University. Let’s begin with a brief introduction of the theme you’ve selected for your presidency, Petroleum++. What will you be emphasizing? There are three elements to this theme: petroleum, the first plus, and the second plus. Let me explain them one at a time. “Petroleum” refers to the challenges petroleum engineers face now and for the foreseeable future to provide the world with the hydrocarbon energy it needs. By hydrocarbons, I mean oil and natural gas, not coal. We can think of the entities that study and predict the world’s future need for energy as three groups: the government entities like the US Energy Information Administration (EIA) and the European Union International Energy Agency (IEA); the major international operators like ExxonMobil, Shell, etc.; and the national oil companies. The predictions provided by all three groups indicate the oil and natural gas share in the energy mix may decline slightly from a little over 50% currently to a little below 50% by 2050. However, the needed volume of hydrocarbons will increase as the world population moves from around 8 billion now to about 9.8 billion in 30 years and as the standard of living continues to improve in the developing regions such as Africa and Asia. When we look at the world’s current reserves and the current technology to produce these, you can add things up and see that we must continue our technical advancements to meet the growing demand for energy.

Comments: The Stark Realities of Energy Supply

Natural gas is considered the transition fossil fuel to move the world toward a meaningful reduction in global greenhouse-gas emissions. But the clampdown of Russia’s natural gas supplies shifted the market’s dynamics, and the repercussions are being experienced around the world. Europe is one of the hardest hit by this disruption in natural gas supplies. In a commentary posted on 18 July, Fatih Birol, executive director of the International Energy Agency, called for coordinated actions across Europe to prepare for the coming winter months and for worst-case scenarios of a complete shutoff of Russian gas and limited availability from other sources. Although Russia resumed a reduced flow of gas to Germany via the Nord Stream pipeline on 21 July, there is no certainty about the fluctuations or duration of the flow. Birol wrote, “Europe is now forced to operate in a constant state of uncertainty over Russian gas supplies, and we can’t rule out a complete cutoff.” The start of Europe’s winter heating season is 1 October. Birol called for action to fill European gas storage to adequate levels by reducing current gas consumption and to put that conserved gas into storage. High natural gas prices have led to gas conservation to some extent, but more efforts are required. He wrote that the gas required to be saved over the next 3 months “is in the order of 12 billion cubic metres—enough to fill about 130 LNG tankers,” equivalent to 424 Bcf. To lend some perspective to this, consider that US LNG exports averaged 10.1 Bcf/D in June. This reflects a 1.5 Bcf/D decrease from May because of a fire on 8 June that shut down Freeport LNG in Texas, according to the US Energy Information Administration (EIA). The agency expects US LNG exports to remain below average at 10.5 Bcf/D in the second half of this year. The Freeport LNG shutdown, and the resulting lower demand for LNG export gas, decreased the US benchmark Henry Hub natural gas spot price. It fell by $1.27/MMBtu to $8.16/MMBtu on 9 June and averaged $7.70/MMBtu in June. EIA expects the spot price to continue to decline to an average of $5.97/MMBtu in the second half of this year. European imports of LNG rose by more than 50% in the first 5 months of 2022 compared with the period a year earlier, according to Bernstein, a Wall Street research firm. Although a wide range of shippers have sent fuel to Europe, the major increases in its LNG imports have come from gas produced from US shale. The increased European demand also increased the price of its imported LNG to nearly nine times what it was about 2 years ago, and those higher prices enticed LNG shippers away from Asia. European futures prices have been around $40/MMBtu. The Wall Street Journal compared that to more than $200/bbl for oil, about twice the price for Brent crude, the international benchmark, as of 22 July. In most years, China, Japan, and South Korea have been the major markets for LNG. During the first 5 months of 2022, Asian imports fell by 8%—in part because of slowing demand from China caused by COVID-19 lockdowns. Birol’s commentary began with this sentence: “The world is experiencing the first truly global energy crisis in history.” For Europe, the Russian invasion of Ukraine also sparked a cost-of-living crisis when oil and gas prices soared. Crises, by definition, require immediate and effective actions.

A Study on Nexus Between Renewable Energy and Fossil Fuel Consumption in Commercial Sectors of United States Using Wavelet Coherence and Quantile-on-Quantile Regression

The inertia of fossil fuels in the commercial sector of the United States has maintained its momentum throughout, and efforts to replace it with renewable energy has continuously been made. This dynamic relationship is impacted by multi-economic and political variables both in the domestic and international markets. In this paper, we have explored the dynamic impact of total renewable energy consumption (RE) on the decomposed wavelet frequencies of energy consumed by fossil fuels (FE) in the commercial sectors of the United States economy. In particular, we have applied wavelet coherence and quantile-on-quantile regression methodologies to evaluate this relationship. The monthly data from the US Energy Information Administration over a period of January 2001 to July 2021 was procured for the present study. Our empirical findings based on wavelet coherence showed significant co-movements between FE and RE with positive association in short-run while negative association in long-run monthly frequency bands. For our five models based on quantiles and decomposed wavelet frequencies of FE, four models show that renewable energy consumption has an antagonistic relation with the FE in the commercial sector of the United States.

Guest Editorial: Aging US Shale Wells: Years of Remaining Opportunities or Growing Asset Retirement Obligations?

A year ago, I wrote a JPT Guest Editorial on stripper wells in the US. It was the result of data analysis that I personally found shocking and the result of frustration I was having with clients looking for acquisitions at that time. The piece was written right before oil prices started an incredible climb and when natural gas prices had been under $3.00/Mcf for an extended period. On the acquisition and divestiture front, although corporate consolidation was ongoing, deal counts were at a decade low, and it was extremely hard to transact. With oil prices at $45/bbl and the so-called “shale bust” of the past few years, many investors would not even consider an unconventional asset. Given this backdrop, I had clients on the hunt for conventional assets with stable base cash flow and limited risk. One client was a very serious buyer; however, some decision makers were adamant about certain asset characteristics, namely conventional, onshore US, certain states, operated working interest, proved producing (PDP), and no stripper wells. Despite this seeming like a reasonable set of criteria, asset after asset kept getting screened out. Finally, I had a call with the CFO and in frustration told him, “They’re all stripper wells.” Something about saying that out loud stuck in my head and got me thinking. I started wondering “how many stripper wells are there?” I began to think about the well count across the US, well IPs (initial production or starting flow rates), and the approximate rates at which I generally saw most wells go uneconomic in financial modeling. Given about 1 million active wells in the US, it seemed like there ought to be a decent percentage of active, producing, conventional wells over the 20–30 BOPD mark. I started pulling well data and found that for many US regions, 95% or more of the active vertical wells were producing 15 BOPD or less. The article generated a lot of interest as it brought to light something many people think is a problem in the back of their mind but had not seen quantified in a simple way. The follow-up question I got over and over was “What about horizontal wells?” The US Energy Information Administration (EIA) estimates that about 80% of US oil and gas wells are producing less than 15 BOEPD. For horizontal wells, EIA estimates about half are 50 BOEPD or less (the use of 6:1 BOE tends to improve the overall daily rate in an amount that is disproportionate to the value and economic impact of adding the gas stream). This rate includes both conventional and unconventional wells. It is natural to assume that the older conventional wells bring down the average and that more recent production from the hottest US shale plays is much higher.

Sustainable Recovery: Regained Optimism

Upstream investment is the main driver for employment in our industry, and forecasts of company spending are eagerly expected by the service sector. I commented in my January column on the initial activity estimates made by West (Evercore). The forecasts have now been firmed up and the increases range between 15 and 17% in 2022 compared to 2021, with growth in all geographical regions. Evercore even projects that 2022 will be the beginning of a multiyear positive cycle for the industry, following 2021 which was a “renaissance of sorts” for the E&P sector. The US Energy Information Administration (EIA) Short Term Energy Outlook for February 2022 forecasts that US oil production will rise to 12.0 and 12.6 million B/D in 2022 and 2023, respectively. The latter would be the highest level ever reached, exceeding the previous record in 2019 by 0.3 million B/D. In their fourth-quarter announcements, the leaders of major service companies made the most optimistic comments for the past several years. Halliburton’s CEO Jeff Miller stated that “simultaneous” growth will occur in both the North American and international markets with a “momentum that I have not seen in a long time.” For Schlumberger’s CEO Olivier Le Peuch, “a strong multiyear upcycle” is underway as capital spending commitments are set to increase by 20% in North America and in the “low to mid-teens” across the broader international market. Such notes from the service sector are welcome news for SPE, as its financial sustainability depends on the engagement of the industry through trade shows, exhibitions, and meetings. Fiscal year 2022 (which ends on 31 March 2022) was the most challenging one in SPE’s history, as we chose not to diminish the level of service to our members and continued to provide virtual and hybrid information channels. SPE’s account balance was positively impacted by the outstanding performance of its reserve funds in financial markets and the support from the US government through instruments such as the Paycheck Protection Program (PPP). These allowed a considerable reduction in loss to an estimated $3 million. For fiscal year 2023 (ending 31 March 2023), the SPE Finance Committee has retained a cautious outlook, with significant uncertainties resulting from the pandemic situation. Early signals coming from the success of the recent hydraulic fracturing technology conferences and exhibitions in Oman and the US are positive. The financial strategy will be adapted in the coming months based on the results of key events such as IPTC, OTC Asia, and the Offshore Technology Conference in Houston.

Case Study: Patent-Pending Rigless Chemical Process Enhances Oil and Gas Production in Eagle Ford

Hydrocarbon production losses resulting from parent-child well interactions during completion operations are a significant challenge in the Eagle Ford. A patent-pending rigless chemical frac hit remediation process was implemented in the Eagle Ford formation resulting in a 60% increase in oil production, a 30% increase in BOE reserves, and a payback in less than 4 months. A thorough engineering and lab study was conducted to design the process which addressed the damage mechanisms of capillary phase trapping, reduced hydrocarbon relative permeability, paraffin deposition, and minor scale deposition. Background and Challenge The Eagle Ford Shale play located across South Texas is a prolific unconventional resource producing approximately 967,000 BOPD and 6 Bcf/D of natural gas through 2021 (US Energy Information Administration). Like other unconventional reservoirs, Eagle Ford wells have high initial production rates but decline rapidly. Later-life production rates can significantly influence well economics and base production profitability. Production in the Eagle Ford rapidly started increasing around 2010 with the implementation of horizontal drilling and hydraulic fracturing. However, as operators started to develop their acreage, they quickly turned to drilling of infill wells, also known as child wells. Lindsay et al. (SPE 189875) reported that by the beginning of 2015, the number of child wells being drilled in the Eagle Ford surpassed the number of existing or parent wells. This resulted in an acceleration of child-parent interactions, defined as interwell communication between the child and the parent during the fracturing of the child well. Known as fracture-driven interference or frac hits, these interactions have been of intense interest in the industry due to the potential degradation of production in both the parent and child well. Miller et al. (SPE 180200) reported that in 1,210 instances studied in the Eagle Ford, the parent well experienced a negative production event approximately 41% of the time. Kairos Energy Services conducted a study on Eagle Ford parent wells that experienced negative production events from a frac hit to quantify the change in production. A total of six wells were analyzed where each had modern completions and were brought onto production in 2019 or later. Decline curve analysis was run on both the oil and gas streams before the frac hit to generate a forecast to compare against actual post-frac-hit production. Actual and forecast production was averaged across the six wells and production responses were analyzed 6 months before and after the frac hit. Fig. 1 shows the forecast vs. actual cumulative production for both oil and gas, respectively. The divergence in production post frac hit can be clearly seen, resulting in an average per well loss of 20,500 bbl of oil and 245,000 Mcf of gas 6 months following the frac hit. All wells showed a significant increase in water production directly after the frac hit, indicating hydraulic communication. The gas/oil ratio (GOR) was significantly suppressed, decreasing from 4,820 ft3/bbl to 3,850 ft3/bbl 6 months post frac hit. The 30-day average water cut also showed a sustained change, increasing from 46% to 63% 6 months post frac hit.

The Association of Coal-Fired Power Plants and the Mortality of COVID-19

With the outbreak and spread of severe acute respiratory syndrome coronavirus 2 (COVID-19), the world was ushered into a global pandemic. One of the most alarming aspects of the disease is the high mortality rate. Previous research has shown that long term exposure to air pollution has been correlated with the mortality rate of respiratory diseases. The focus of this study was to determine if there was any association between the mortality of COVID-19 and one of the primary producers of air pollution, coal-fired power plants. Using data from the US Energy Information Administration, John Hopkins University, and census department, a chi-square test and a poisson regression analysis were conducted to determine if living in proximity to coal-fired power plants had any effects on the mortality of COVID-19. The chi-square test results showed that there was no statistical significance as the variables showed independence. These results illustrate that there is no association between coal-fired power plants and the mortality rate of COVID-19. To expand on the results of the chi-square test, a poisson regression analysis was performed to account for the presence of confounding variables. This analysis showed similar results to the chi-square test, but due to issues with outliers in the data causing overdispersion, the model was unable to be accurately conducted, making all results inconclusive. With the inconclusive results of the poisson regression analysis, the conclusions drawn from the chi-square test were not able to be generalized as they were not verified in the presence of confounding variables.

Major US electric utility climate pledges have the potential to collectively reduce power sector emissions by one-third

Major US electric utility climate pledges have the potential to collectively reduce power sector emissions by one-third

Alaska’s North Slope May Yet See Its Renaissance in Arctic Exploration

It wasn’t too long ago that Arctic oil and gas exploration enjoyed celebrity status as the industry’s last frontier, chock full of gigantic unexplored hydrocarbon deposits just waiting to be developed. Fast forward and less than a decade later, the same climate change that made Arctic oil and gas more accessible has caused an about-face as governments and the world’s supranational energy companies rebrand and target control of greenhouse gases (GHG) to achieve carbon neutrality by 2050. Among countries with Arctic coastlines, Canada has focused its hydrocarbon production on its oil sands which sit well below the Arctic Circle; Greenland has decided to not issue any new offshore exploration licenses (https://jpt.spe.org/greenland-says-no-to-oil-but-yes-to-mining-metals-for-evs), and while Norway is offering licenses in its “High North,” the country can’t find many takers. The Norwegian Petroleum Directorate (NPD) reported that while 26 companies applied for licenses in 2013, this year’s bid round attracted only seven participants. Norway is Europe’s largest oil producer after Russia with half of its recoverable resources still undeveloped and most of that found in the Barents Sea where the NPD says only one oil field and one gas field are producing. That leaves Russia and the US—geopolitical rivals which are each blessed with large Arctic reserves and the infrastructure to develop those riches—but whose oil and gas industries play different roles in each nation’s economy and domestic political intrigues. Russia sees its Arctic reserves, particularly gas reserves, as vital to its national security, considering that oil and gas accounts for 60% of Russian exports and from 15 to 20% of the country’s gross domestic product (GDP), according to Russia’s Skolkovo Energy Centre. With navigation now possible year­round along the Northern Sea Route, Russia’s LNG champion and its largest independent gas producer, Novatek, is moving forward with exploration to expand its resource base and build infrastructure to ship product east to Asia and west to Europe. https://jpt.spe.org/russian­lng­aims­high­leveraging­big­reserves­and­logistical­advantages As a result, Russia’s state­owned majors—Rosneft, Gazprom, and Gazprom Neft—are lining up behind their IOC colleague as new investment in Arctic exploration and development is encouraged and rewarded by the Kremlin. In contrast, the American Petroleum Institute reports that the US oil and gas industry contributes 8% to US GDP, a statistic that enables the US to have a more diverse discussion than Russia about the role that oil and gas may play in any future energy mix. That is unless you happen to be from the state of Alaska where US Arctic oil and gas is synonymous with Alaskan oil and gas, and where the US Geological Survey estimates 27% of global unex­plored oil reserves may lie. Though Alaska is responsible for only 4% of US oil and gas production, those revenues covered two-thirds of Alaska’s state budget in 2020 despite the state’s decline in crude production in 28 of the past 32 years since it peaked at 2 million B/D in 1988, according to the US Energy Information Administration (EIA).

Comments: Oil Demand Optimism

Forecasts for oil demand are looking up, according to OPEC and the International Energy Agency as of mid-July. Will the optimistic views prove to be on target? We have learned how the market can shift or wildly careen, both historically and in the very recent past. Looking at the forecasts, which reflect a consensus of sorts, is encouraging for producers. OPEC’s monthly report of 15 July projected global oil demand to reach nearly 100 million B/D next year, a level similar to pre-pandemic in 2019. The 2021 oil demand growth remains unchanged at 5.95 million B/D, or approximately 6.6%. Led by demand growth in the US, China, and India, a 3.4% increase is expected in 2022 to 99.86 million B/D and would average more than 100 million B/D in the second half of the year. “Solid expectations exist for global economic growth in 2022,” OPEC said. “These include improved containment of COVID-19, particularly in emerging and developing countries, which are forecast to spur oil demand to reach pre-pandemic levels in 2022.” If the actual recovery tracks with these predictions, OPEC can dial back further its record-level supply cuts made in 2020. The IEA points to the growth expected in global electricity demand as spurring fossil-fuel demand, including oil, coal, and natural gas. After falling by around 1% in 2020, electricity demand growth may approach 5% in 2021 and 4% in 2022. The Asia Pacific region will account for the majority of the increases. China, the world’s largest consumer of electricity, leads the tally, accounting for more than 50% of the 2022 growth. India, the third largest, will account for 9% of the global electricity growth. Renewables are expected to be able to serve around half of the projected growth in global demand in 2021 and 2022. IEA wrote, “Renewable electricity generation continues to grow strongly—but cannot keep up with increasing demand. After expanding by 7% in 2020, electricity generation from renewables is forecast to increase by 8% in 2021 and by more than 6% in 2022.” Fossil fuel-based electricity is set to cover 45% of additional demand in 2021 and 40% in 2022. After declining by 4.6% in 2020, coal-fired electricity generation will increase by nearly 5% in 2021, exceeding pre-pandemic levels. In 2022, it will grow another 3% and could reach an all-time high. Natural gas-generated electricity lags coal because it is less commonly used in the Asia Pacific and competes with renewables in the US and Europe. It is expected to increase globally by 1% in 2021 and by nearly 2% in 2022 after declining by 2% in 2020. The US Energy Information Administration published a global financial review last month of 91 oil and gas companies, most headquartered in the US, in the first quarter 2021. It indicated that companies are implementing their plans announced over the past year to reduce capital expenditures to pay down debt. Capital expenditure in 1Q2021 was reported as $48 billion, 28% lower than in 1Q2020 and the second- lowest amount for any quarter since 2016. Cash from operations in Q1 this year totaled $79 billion, 19% higher than in 1Q2020; about 76% of companies had positive free cash flow. Overall, the companies decreased debt by $16 billion in 1Q2021, and the long-term debt-to-equity ratio decreased to 54%.

Technology Focus: Natural Gas Processing and Handling (April 2021)

In 2020, the spot prices of natural gas hit a record low in the US, reaching the lowest annual average price in more than a decade. Based on US Energy Information Administration (EIA) data, the average annual spot price reported in 2020 was $2.05 per million British thermal units (MMBtu). In the first few months of the year, reports from the EIA showed that natural gas prices started declining amid mild winter temperatures that resulted in a decline in the demand for natural gas for space heating. In March 2020, following the onset of the COVID-19 pandemic, the already declining natural gas prices plummeted further. This decline continued through the first half of the year. The EIA reported the average monthly Henry Hub spot price in the first 6 months at $1.81/MMBtu. June saw the lowest monthly natural gas price in decades (Henry Hub price aver-aged $1.66/MMBtu). Natural gas prices recovered in the second half of the year as natural gas production decreased and global exports of liquefied natural gas increased. Natural gas consumption in the residential, commercial, and industrial sectors declined in 2020, according to the EIA. Milder winter temperatures were a major contributor in the first quarter of the year, but overall declining consumption was attributed to reduced economic activities as a result of the COVID-19 pandemic. On the other hand, the consumption of natural gas for electric power generation registered an overall increase of 2% more than the 2019 average. According to the EIA, citing S&P Global Platts, this increase was attributed to power producers switching to cheaper natural gas from coal to meet the increased demand for electric power for cooling as summer temperatures increased. The EIA in its Annual Energy Outlook 2021 projects that the industrial and electric power sectors and net exports will drive the growth in US energy consumption between 2020 and 2050. Natural gas consumption in other sectors is expected to increase steadily or remain flat. The EIA forecasts that natural gas production will increase as consumption increases and prices will stay low relative to past prices. The EIA expects continued growth in natural gas exports as natural gas production surpasses natural gas consumption. Globally, the International Energy Agency forecasts a recovery in global demand for natural gas in 2021 led by growth in the Asia Pacific region as emerging markets recover. The US will continue to play a significant role as one of the largest producers and contributors to natural gas supply growth. Recommended additional reading at OnePetro: www.onepetro.org. SPE 200300 - Overcoming Challenges in the Development of Underground Gas Storage by Ammar Alali, Saudi Aramco, et al. OTC 30602 - Offshore LNG and Gas Monetization by Femi Adeoye Alabi, Total SPE 200147 - Development of the Underground Gas Storage and Construction of the Salt Cavern Storage in China by Peng Chen, CNPC, et al.

Protocol to Assess the Impact of Crude Oil Price Fluctuations on Future Asphalt Prices

It is clear for the transportation industry that asphalt prices are heavily affected by changes in the crude oil market. This occurs because asphalt is a byproduct of the process of refining crude oil. However, there is still a lack of research on assessing the economic implications of this relationship. This paper assesses those implications through an innovative statistical process designed to quantify the economic correlation between asphalt and crude oil price fluctuations in Alabama. The proposed statistical process is used in this paper to model the relationship between the Alabama Department of Transportation’s (ALDOT’s) monthly asphalt price index and a national crude oil index published by the US Energy Information Administration. The process quantifies the relationship between these two commodities in relation to two metrics: (1) the time gap between an observed change in the crude oil index and its corresponding impact on the asphalt price index and (2) the magnitude of that impact. It was found that the most likely time gap between crude oil and asphalt price fluctuations in Alabama is 3 months, with a change ratio of 0.58. This means that a 1% increase in the price of crude oil would most likely affect the Alabama asphalt market 3 months later with a price increase of about 0.58%. Recognizing that these are just average values, the paper also presents a risk assessment tool that provides ALDOT with the probability of occurrence of different scenarios taking into consideration the observed variability in time gaps and change ratios.

China’s Unconventional Challenge Spurs New Thinking on Shale and Tight Reservoirs

Despite possessing some of the world’s largest shale-gas resources, China is likely in 2020 to have produced less than half of the 30 Bcm per year in shale gas that the government set as a goal in its latest Five-Year Plan. While such a small volume may make shale production seem inconsequential to China’s overall energy balance, it is clear that when it comes to developing unconventional hydrocarbons, China is playing a long game. With regard to shale alone, a 2013 US Energy Information Administration study noted that China has the world’s second-largest technically recoverable shale-gas resources at an estimated 1,115 Tcf; the US is first with 1,161 Tcf. Even more to the point, China is one of only four countries (including the US, Canada, and Argentina) that produce commercial volumes of both shale gas and of tight oil. But it is the lack of efficient technologies and infrastructure that stand in the way of China besting the US and creating its own “shale revolution.” China’s most attractive reserves occur in remote, mountainous areas where, in some cases, shale resources can lie as deep as 3500 m. In separate papers presented in October during the 2020 SPE Russian Petroleum Technology Conference, the China National Petroleum Company (CNPC) detailed new technologies it is applying to meet some of these challenges. Paper SPE 202066, coauthored by subsidiaries of CNPC, Downhole Service Company and CCDC Petroleum Drilling & Technology Company Ltd., details the application of enhanced-hydraulic- fracturing technology (EHFT) to raise the effective stimulated reservoir volume (SRV) in the Sichuan shale basin. A second paper (SPE 202062), coauthored by CNPC and Halliburton, offers a case study in tight-oil production in Daqing employing an intensive fracture-cluster-completion strategy using a microemulsion flowback technology. The Spice in Sichuan Shale China boasts three shale basins (Sichuan, Tarim, and Yantze), but its principal development focus is in the southwestern province of Sichuan, which holds half of the country’s shale reserves. In developing fields such as Weiyuan, Changning, and Jiaoshiba, producers target the Ordovician Wufeng-Silurian Longmaxi formation. The total proved geological reserves of these three gas fields exceeds 500 Bcm, the authors noted in their paper. To develop infrastructure supporting industrial-scale operations and to introduce and test new technologies to raise shale output, China has established several national pilot demonstration areas. One of those is the Weiyuan national shale demonstration area in south Sichuan, where the authors quote an annual production of 2.5 Bcm. Staged horizontal fracturing is the main technology used at Weiyuan and other Chinese shale fields as producers strive to expand the fracture extension area, increase the reconstruction volume, and improve the productivity of single wells. An analysis of production data from Weiyuan showed, however, that the long-term conductivity of fractures is limited because the length and height of supporting fractures are short. Thus, because of the limited volume of reconstruction, production decreases rapidly and efficiency suffers as pressure declines.

Should North Carolina require more efficient water heaters in homes? A cost-benefit analysis

In 2015, water heaters were the second largest end-user of residential energy. Heat pump (HP) water heaters are several times more efficient than the electric resistance (ER) water heaters common in homes. Currently, North Carolina only requires electric water heaters with tanks larger than 55 gallons to be HP water heaters in new homes, thus allowing inefficient ER water heaters in smaller residences. We considered a hypothetical change to North Carolina's building code requiring HP water heaters in all new residential units constructed in 2018. Using housing data from the US Census Bureau, along with electricity rates and emissions factors from the US Energy Information Administration, we quantified changes in costs expected from tightened efficiency requirements. We estimate that requiring HP water heaters in all new residential construction incurs a one-time statewide cost of $29.5 million, but leads to a total 10-year savings of $108.7 million for residents, as well as 10-year reductions in carbon dioxide emissions of 441,000 metric tons. When rebates from electric utilities are included, total 10-year statewide savings increase to $125.3 million. Our results show that economic and environmental benefits can be realized through changes to state building codes, thus obviating the need for legislative action.

Intraday Return Predictability in the Crude Oil Market: The Role of EIA Inventory Announcements

We study the impact of the announcements released by the US Energy Information Administration (EIA) crude oil storage every Wednesday at 10:30 ET (the beginning of the third half-hour interval) on intraday return predictability, that is, intraday momentum. Our results indicate that returns on the third half-hour on EIA announcement days can significantly and positively predict the returns in the last half-hour, whereas, on non-EIA announcement days, only returns in the first half-hour have significant predictability. The dominant source of prediction in the first half-hour return mainly comes from the overnight component. EIA announcements contribute to intraday momentum because they attract more informed traders and because the period surrounding their release is often associated with a reduction in liquidity. Substantial economic gains can be made by using efficient intraday predictors as trading signals.

Harnessing Interfacial Electron Transfer in Redox Flow Batteries

Summary Redox flow batteries (RFBs) have garnered increasing attention for their potential to enable the widespread adoption of renewable electricity. However, a critical need associated with the continued development of this technology involves designing electrode-electrolyte interfaces that exhibit rapid, stable electron transfer kinetics. This targeted review outlines key challenges associated with measuring and enhancing the electron transfer kinetics of established and emerging flow battery active materials. We discuss several promising opportunities for advancing flow battery science and technology using the tools of applied electroanalysis and catalysis science. These challenges and opportunities are broadly relevant for future research directed at advancing the commercial adoption of RFBs for grid-scale energy storage.

CURRENT TRENDS AND PROSPECTS ROR THE DEVELOPMENT OF RENEWABLE ENERGY IN TERMS OF COVID - 19

Crisis related to distribution of COVID-19 requires significant state involvement in the response, which includes the definition of strategies formation and direct intervention in to the socio-economic processes. Governments of countries are addressing the development of stimulus and recovery packages strategies what have a goal to form in the future necessary potential for society and economy on the whole. In given environment, stable assets are needed, including an inclusive energy system capable of supporting energy development in accordance with the United Nations Sustainable Development Program and the 2016 Paris Agreement, this requires further research of the prospects for innovative development of renewable energy sector in the crisis of COVID-19 in the transition from the use of fossil fuels to the use of renewable energy sources. Global forecasts from the International Renewable Energy Agency, the International Energy Agency, and the US Energy Information Administration have suggested ways to transform the global energy system. China's hybrid energy market is showing an increase in wind and solar energy production. Reduced costs in the United States have stimulated an increase in renewable energy capacity. In Ukraine, the important role of alternative energy can be identified in the stabilization of Ukraine's agro-industrial complex. In the article reviews current trends and conditions in the development of the energy sector in the transition from the use of fossil fuels to the use of renewable sources in China, United States and Ukraine in terms of forecasting generation and justification of investment directions. A number of technical challenges and problematic aspects of management in the renewable energy sector in Ukraine are highlighted. Long-term goals are proposed for all stakeholders of the energy system in the transition from the use of traditional fuel to the use of biopropellant. The conceptual principles and prospects of scientific research in the formation of the National Renewable Energy Development Plan until 2030 are also outlined.

Development of a turbulent burning velocity model based on flame stretch concept for SI engines

According to the US Energy Information Administration, fossil fuels will remain the main source of energy for transportation over the next decades and thus the combustion of these fuels remains an important concern.This research studied the flame propagation under engine in-cylinder conditions and developed a correlation for turbulent burning velocity based on the global flame stretch concept. To study the impact of engine operation on flame stretch, two speeds, two loads, and three fuel-air mixtures were investigated. The flame front was determined by processing images of the flame natural luminosity.A turbulent burning velocity model was developed using dimensional analysis. The model showed that the turbulent burning velocity decreased due to flame stretching. Higher engine speeds increased the turbulent burning velocity by increasing the turbulent intensity, yet a tradeoff between the flame stretch and the turbulent burning velocity due to higher engine speed was observed. In cases where the flame distortion was very high, the flame stretch may cancel out any benefits of a large enflamed area.Incorporating the flame stretch into the burning velocity model and coupling the developed model with GT-Power simulation software revealed that the stretch may result in a 35% reduction in turbulent burning velocity.

E&P Notes (July 2020)

E&P Notes (July 2020)

Comments: In Just Three Months, Our Industry Changed

Editor's column It has now been nearly 3 months since the one-two punches of an unprecedented modern-day pandemic and a free fall in oil prices due to the oversupply of oil resulting from a tremendous, sudden drop in demand. The domino effects across the globe continue to evolve in economies, industries, and personal lives. West Texas Intermediate hovers around $20/bbl (as of mid-April) after starting the year in the $60s: a drop in oil price of two-thirds while global oil demand continues to sputter. The International Energy Agency (IEA) forecast the demand to be down in April by 29 million B/D, a nearly 30% decrease from the world’s daily consumption a year ago of 100 million B/D. It added that demand has not been this low since 1995. The US Energy Information Administration expects global petroleum and liquid fuels demand to decrease by 5.2 million B/D in 2020. As the saying goes, “You do the math.” The math was done by the world’s operators, oilfield services companies, and related industry players—and the answers in far too many cases resulted in necessary, hard decisions. Furloughs and layoffs were announced early on, and capital expenditures were slashed as much as 30 to 50%. In many cases, companies soon thereafter announced further cuts in personnel and budgets. An example of a weighty cut was Abu Dhabi National Oil Company’s (ADNOC) termination of two contracts worth $1.65 billion granted to Petrofac for work to be done for the Dalma gas development project located off the north-west coast of the Emirate of Abu Dhabi. The contracts were awarded in February; in March, ADNOC notified contractors and suppliers it would review existing deals to find ways to reduce costs due to the steep slide in oil prices. On 16 April, the deal was called off. Petrofac said it is committed to working with ADNOC over the coming weeks to explore “alternative options” for the work. The oil and gas industry has demonstrated resiliency many times over in its long history, and as it kicks off the first-quarter earnings season, its guidance calls will reveal the plans and actions needed to move forward in the near term. The uncertainty wrought by the repercussions of the pandemic and supply/demand imbalance has introduced a host of unknown factors beyond anyone’s direct control. But companies can directly control their operations and business practices and will be presenting their full-year 2020 outlook in coordination with the first-quarter results. Diligence and resilience, based on experience and hard lessons learned, go hand in hand and will guide each company’s best attempts to manage the unique unpredictability it faces today.