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HartEnergy.com
Mary Holcomb
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Faiza Rizvi
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Chief Digital Officer

The Colorado School of Mines Reservoir Characterization Project featured field projects from across the globe including the study of legacy wells and wells currently being drilled by HighPoint Resources in the Denver-Julesburg Basin.
The consolidation trend among oil and gas producers will continue before vaccines pave the way for recovery, Pioneer CEO Scott Sheffield said Dec. 1 at the Reuters Future of Oil & Gas 2020 virtual conference.
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y definition, it’s impossible to definitively answer this question. Watershed moments, of course, are usually deciphered in hindsight. But what the heck, let’s throw caution to the wind and try to look ahead anyway.
I had been pondering this question in my mind for the better part of autumn, and then I got the chance to ask it directly to someone who understands much more about the oil and gas industry and its history than me. So I asked Daniel Yergin, the vice chairman of IHS Markit and Pulitzer Prize-winning author, during a one-on-one video interview about his latest book, “The New Map: Energy, Climate and Clash of Nations,” as well as the industry as a whole. Not surprisingly, I got a very insightful and even more thought-provoking answer.



n September 2020, Weatherford International named Girish Saligram the new CEO. Officially taking over a month later, Saligram heads one of the world’s largest oilfield service companies. Weatherford’s offerings include tools and systems for drilling, completions, production, formation evaluation, tubulars, interventions and abandonment.
Before joining Weatherford, Saligram served Exterran Corp. as COO and previously as president of Global Services after joining the company in 2016. Prior to Exterran, Saligram spent 20 years with GE as a business leader in industry sectors across the globe, including his last position as general manager of Downstream Products & Services with GE Oil & Gas. Prior to that, Saligram led the GE Oil & Gas Contractual Services business based in Florence, Italy. Before his eight years in the oil and gas sector, Saligram spent 12 years with GE Healthcare in engineering, services, operations and other commercial roles.


Improve Your ESG Score
he cost of hydraulic fracturing on a tight gas or oil well in North America is the single largest item in a well’s AFE and proppant delivered is the largest single component of the fracturing invoice. PropX has developed a method to cut total delivered cost of proppant while reducing an operator’s or service company’s environmental impact.
This new method (patent pending) involves a system to store and deliver wet sand to the frac blender. Skipping the drying process after mined sand is washed saves significant energy and the CO2, VOCs, Nox and silica dust emissions are reduced or eliminated.

n June 2020, ChampionX Corp. completed the merger of the businesses of Apergy Corp. and ChampionX Holding Inc., the former upstream energy business of Nalco Champion. Apergy then changed its name to ChampionX Corp. Now ChampionX has a team of nearly 7,000 people globally, and the company offers chemical, artificial lift, drilling and digital technologies for the reservoir, production, midstream and water treatment markets.
“The creation of ChampionX through the merger of Apergy and the Nalco Champion upstream chemicals business has been transformative and a complementary combination in strategic, operational and financial dimensions,” President and CEO Soma Somasundaram told E&P Plus. “Our combination created a global leader in production optimization and an essential player in the oil and gas market with a strong portfolio, global customer base and footprint, and strong financial profile.”
Hydraulic Fracturing Trends

s the saying goes, hindsight is 20/20. But as the industry looks back on the past year, it might be hard-pressed to come away with a clear vision of 2020. The oilfield services (OFS) sector, and in particular the hydraulic fracturing market, took the brunt of the blow, with many pressure pumpers seeing almost no work by late spring and early summer.
According to Westwood Energent, the number of frac crews operating in the Permian numbered 18 to 20. Even as pandemic restrictions began being lifted, and demand for oil started to marginally improve by the early fall, the OFS sector remained mostly stagnant as operators worked through their inventory of DUCs.
But as the calendar has flipped to a new year, the fracking industry is both taking stock of lessons learned from 2020 and pushing forward with innovations and technologies designed to optimize efficiencies for both operators and service providers. Meanwhile, as shale producers increasingly put more effort on achieving ESG goals, service providers are bringing to market systems and tools that cut down on emissions and generally reduce the carbon footprint of fracturing operations.
Hydraulic Fracturing Trends

s the saying goes, hindsight is 20/20. But as the industry looks back on the past year, it might be hard-pressed to come away with a clear vision of 2020. The oilfield services (OFS) sector, and in particular the hydraulic fracturing market, took the brunt of the blow, with many pressure pumpers seeing almost no work by late spring and early summer.
According to Westwood Energent, the number of frac crews operating in the Permian numbered 18 to 20. Even as pandemic restrictions began being lifted, and demand for oil started to marginally improve by the early fall, the OFS sector remained mostly stagnant as operators worked through their inventory of DUCs.
But as the calendar has flipped to a new year, the fracking industry is both taking stock of lessons learned from 2020 and pushing forward with innovations and technologies designed to optimize efficiencies for both operators and service providers. Meanwhile, as shale producers increasingly put more effort on achieving ESG goals, service providers are bringing to market systems and tools that cut down on emissions and generally reduce the carbon footprint of fracturing operations.
Hydraulic Fracturing Trends
hen we talk about the digitization of well completions, forget the buzzwords you are used to reading; while they sound nice, they mean nothing. Instead, let’s focus on the concrete, monetizable solutions that operators are realizing right now.
Today, oil and gas companies face one main problem: the cost to complete a well is too high given current commodity prices. Operators need to improve their financial metrics by reducing the cost to complete a well.




iscover innovations for the next fracturing revolution
Profound scientific knowledge has catalyzed advancements in intelligent systems and applications for hydraulic fracturing. Industry professionals leading these innovations will present their findings Feb. 2-4 at the 2021 SPE Virtual Hydraulic Fracturing Technology Conference and Exhibition. The conference features a diverse portfolio of next-generation technologies, sustainable developments and best practices.
Fracture diagnostics sessions at this event will include a novel method and its application to define a maximum horizontal stress and stress path. Among other demonstrations are field applications of sealed wellbore pressure monitoring to evaluate completion effectiveness.
US Shales Scorecard
US Shales Scorecard
s the industry often does, it will one day look back on 2020 in a variety of contexts—how demand destruction and a global price war sunk oil prices to previously unseen levels, how mounting debt problems coupled with a lack of investment opportunities drove widespread consolidation, and how production shut-ins crippled operators.
The 2020 details vary depending on which of the seven major shale basins are being reviewed:
- Activity dropped to merely a crawl in places like the Rockies and the Midcontinent;
- The Permian behemoth took a punch but quickly got up off the mat; and
- Gas plays like the Haynesville and Marcellus/Utica rode on the coattails of Henry Hub prices that reached $3/MMBtu by early fall 2020.



210 in October 2020



per well have grown by
21%

7,592 in September 2020
output by second-quarter 2021

gas production for 2021


210 in October 2020


for North American tight liquids

needed to maintain flat oil output

21%

8,533 in July 2019
7,592 in September 2020

42%
is the average reduction in permit counts in the seven major shale basins between April 2020 and July 2020 (compared to November 2019 to February 2020 timeframe)

105%

Jump to a topic:
- 0:46—Shale outlook
- 2:00—Resurgence of virus and impact on Europe’s oil market
- 4:15—Extension of OPEC+ cuts into 2021
- 7:43—Joe Biden and the energy transition
- 12:26—European oil majors realigning goals with net zero 2050
- 17:13—‘Hydrogen will be a game changer’
- 21:10—Digitalization will shape recovery
- 28:46—Final thoughts on the industry’s path forward
n an exclusive roundtable discussion, analysts offered a bullish outlook for 2021, expressing cautious optimism that a vaccine breakthrough will significantly improve oil demand and prices as the economy goes back to normal in the second half of 2021. Speakers in this in-depth discussion include:
- Dr. Keith Myers, president of research with Westwood Global Energy;
- Dr. Yousef Alshammari, CEO and head of oil research with CMarkits; and
- James West, senior managing director with Evercore ISI.

ew research from DNV GL reinforces the message that pressure on the global oil and gas industry to decarbonize its value chain to maintain its social license to operate will continue to increase in a rapidly changing world.
The 2020 Energy Transition Outlook estimates that fossil fuels will account for 74% of world energy-related CO2 emissions in the mid-century and more than 80% of combined emissions of CO2 and methane (measured as CO2 equivalents). While global energy-related emissions will be roughly halved between 2018 and 2050, emissions from the entire oil and gas value chain will fall by a third.

he U.S. oil, gas and chemicals (OG&C) industry brought the country to an era of energy security on the back of its nearly 1.5 million-strong workforce. This talent enabled the upstream shale boom and downstream energy renaissance in the country, and the industry in turn rewarded its workforce generously with large paychecks. In fact, the U.S. energy and utility sector had the highest median salary of any industry in the S&P 500 in 2018.
However, supply from this boom started running ahead of oil demand. The result? Oil started its longest and deepest downturn in 2014, and the growth narrative changed into mass layoffs of about 200,000 employees between 2014 and 2016. The COVID-19-led lockdowns and the resulting oil price crash to negative levels exacerbated the situation, leading to the fastest layoffs in the industry: about 107,000 workers were laid off between March and August 2020.
xpert knowledge resides in individuals, but data belong to everyone. The petroleum industry is adopting a more integrated team approach to well planning and drilling, with software technology bringing engineering and geoscience closer together for better well trajectory designs. The ability to integrate all available geological and geophysical (G&G) data and related interpretations, and also identify the locations and paths of planned and existing wells, optimizes well planning in unconventional and fractured reservoirs.
A collaborative team of technical experts with access to all relevant data can provide benefits in terms of safety, efficiency and delivery cycle times, and help maximize the project’s return on investment. Software advances that support the integration of engineering planning and geoscience data will assist these new collaborative teams to function effectively.
he oil and gas industry is facing an unprecedented challenge to operate more efficiently and sustainably than ever before. The industry will be unable to meet this challenge without using disruptive technological innovations. More specifically, the well construction domain needs to transform and can do so by leveraging intelligent and autonomous systems.
An autonomous and self-steering bottomhole assembly (BHA) that is supported via a fully integrated data architecture eliminates siloed and independent workflows and harmonizes all aspects of well construction operations. The end result is an autonomous system that can drill wells for any field, rig or trajectory in the most efficient and consistent manner possible. Through increased efficiency and consistency, operators can deliver better drilling outcomes and economics, which enables optimal equipment and power utilization, minimized HSE risks and a reduction of the carbon footprint.
he world of managed pressure drilling (MPD) is a confusing one. For instance, a term like “lite MPD” means “lightweight”—not “light on capabilities.” Terms like “flex” are used to describe multiple service levels. Operators often discuss electric and hydraulic choke control methods and argue about which system controls better—when actually they are manipulating surface backpressure to hold a constant bottomhole pressure, which is usually over a mile away down a hole filled with all different types of compressible fluids, temperature variations and complex geometries. And what does it really mean to have an MPD-ready rig?
The MPD Committee of the International Association of Drilling Contractors strives to standardize communication in this area and to provide terms and tables that will clarify the capabilities and levels of MPD. There are so many different owners of equipment and many different ways that MPD systems are being used, so it can be quite a challenge to properly standardize these industry terms.
However, it should be an easier task to standardize the levels of automation in MPD systems, as these levels can be classified following the same standards that the Society of Automotive Engineers (SAE) has released for automated vehicles. The SAE J3016 standard defines six levels of driving automation, from SAE Level Zero (no automation) to SAE Level 5 (full vehicle autonomy). Leveraging the same structure as the SAE J3016 standard, the adaptation for MPD is shown in Figure 1.
he world of managed pressure drilling (MPD) is a confusing one. For instance, a term like “lite MPD” means “lightweight”—not “light on capabilities.” Terms like “flex” are used to describe multiple service levels. Operators often discuss electric and hydraulic choke control methods and argue about which system controls better—when actually they are manipulating surface backpressure to hold a constant bottomhole pressure, which is usually over a mile away down a hole filled with all different types of compressible fluids, temperature variations and complex geometries. And what does it really mean to have an MPD-ready rig?
The MPD Committee of the International Association of Drilling Contractors strives to standardize communication in this area and to provide terms and tables that will clarify the capabilities and levels of MPD. There are so many different owners of equipment and many different ways that MPD systems are being used, so it can be quite a challenge to properly standardize these industry terms.
However, it should be an easier task to standardize the levels of automation in MPD systems, as these levels can be classified following the same standards that the Society of Automotive Engineers (SAE) has released for automated vehicles. The SAE J3016 standard defines six levels of driving automation, from SAE Level Zero (no automation) to SAE Level 5 (full vehicle autonomy). Leveraging the same structure as the SAE J3016 standard, the adaptation for MPD is shown in Figure 1.
he evolution of frac plugs has been a key enabler in the economic development of unconventional reservoirs in the U.S., according to John Ray, vice president of completions with Innovex Downhole Solutions.
“The industry has experimented with a variety of different completion technologies over the last 10 years, but we are firm believers that frac plugs are the simplest, most robust way to complete horizontal wells.”
here are a variety of triggers that can lead to surface and underground blowouts on oil and gas wells. Drilling and workover operations that exhibit a compromised hydrostatic barrier can permit formation fluids to come to surface. Additionally, a surface barrier may fail on a production well. In both cases, these events could lead to a surface blowout.
On the other hand, underground blowouts can happen if there is formation flow from a high-pressure reservoir to a formation with lower integrity. This is typically the result of some type of downhole failure.
A particularly severe event can occur if loss of well control barriers follows. The crucial factor in the ability to cap a surface blowout, or reenter and concentrically kill an underground blowout, is the well control specialist’s ability to gain access to the wellhead.
he Marine Well Containment Co. (MWCC), which was established in the aftermath of the Deepwater Horizon disaster, has designed a comprehensive emergency response program to contain compromised deepwater wells in the Gulf of Mexico (GoM). In an exclusive interview with E&P Plus, MWCC CEO David Nickerson discussed how the company remained continuously ready to respond to a deepwater well control incident in the GoM amid a global pandemic and higher than average tropical storm activity.
volution is underfoot in the 160-year-old oil and gas industry. It’s a slow change spurred on by digitalization, and the efficiencies and opportunities it creates, as well as a call to action for our climate. The energy sector is responding by turning its attention toward a sustainable future.

.S. oil and gas companies are seeking new technologies to address an old problem: gas leaks. Many organizations have long relied on fixed hardware or manual assessments to monitor leaks. Naturally, the occurrence of a major leak requires immediate response, but detecting the source of a leak from the beginning can ensure a quick and safe correction or evacuation.
Blackline Vision, the data science team of Blackline Safety, is developing its AI Gas Leak Detection module, which resolves this issue by leveraging artificial intelligence (AI) to automate the process while providing situational awareness and connectivity. The module provides advance alerts of gas leaks by identifying patterns in low-level gas readings streamed to the Blackline Safety Cloud from G7 wearable gas monitors.



he Midland Basin region of the eastern Permian Basin has seen a steady amount of new E&P since 2011.
The Midland Basin underlies an area approximately 250 miles wide and 300 miles long, and it includes the West Texas counties of Borden, Dawson, Martin, Midland, Upton, Reagan, Glasscock and portions of Andrews, Crane, Gaines, Ector, Terry, Lynn Howard and Irion counties.
The Midland Basin is bounded to the east by the Eastern Shelf through a series of north-south trending fault segments, to the north by the Northwest Shelf and to the west by uplifted areas of the Central Basin Platform. Southward, Midland Basin formations thin out into the Ozona Arch, an extension of the Central Basin Platform, which separates the Delaware and Midland basins.


Two Campbell County, Wyo., Parkman producers were completed by EOG Resources Inc. The wells were drilled in Crossbow Field on a pad in Section 5-42n-72w. The #0508-01H Congo was drilled to 16,820 ft (true vertical depth of 7,446 ft). It produced 1,017 of 58°API oil, 1.459 MMcf of gas and 1,095 bbl of water per day from perforations at 7,854 ft to 16,754 ft after 22-stage fracturing. The offsetting #0508-02H Congo was drilled to 17,356 ft (7,467 ft true vertical depth). It flowed 1,210 bbl of 57°API condensate, 1.079 MMcf of gas and 987 bbl of water daily after 24-stage fracturing. Production is from perforations at 7,619 ft to 17,292 ft after 24-stage fracturing.
A Hawkeye Field completion by Hess Corp. initially flowed 4,082 bbl of 40°API oil, with 7.107 MMcf of gas and 1,302 bbl of water per day from Middle Bakken. Located in Section 34-152m-95w in McKenzie County, N.D., #152-LE-95-3427H-1 HA-Nelson A was drilled to 21,294 ft (10,698 ft true vertical), and production is from a perforated zone at 11,155 ft to 21,113 ft. It was tested on a 42/64-inch coke, and the flowing casing pressure was 2,044 psi.


GeoPark announced results from an appraisal test in Colombia’s Block CPO-5. The well, #2-Indico, was drilled to 10,925 ft and flowed 5,200 bbl of 35°API oil per day from Une (LS3). It was tested on a 40/64-inch choke, and the wellhead pressure was 330 psi. According to the company, the well bottomed within one-half mile to the north and 151 ft down-dip of a previous test, #1X-Indico, which hit a net pay zone of approximately 161 ft. Additional production testing is planned. The drilling rig is being moved to the nearby Aguila exploration prospect in the block to test several targets in Une (LS3). Up to six more wells are planned for the block by GeoPark.
President Energy reported test results from exploration well #1-xEVN near Estancia Vieja Field in northern Rio Negro Province, Argentina. Two pay intervals in the previously untested Estancia Vieja North structure were confirmed by well logging, with an unreported amount of 36°API oil and gas flowing to the surface. The preliminary testing indicated that IP levels can be expected in line with P50 pre-drill expectations of more than 200 bbl/d of oil plus associated gas from this lower interval. The well is near the main Estancia Vieja pipelines and facilities. Additional exploratory drilling and testing are planned.






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istorically, there has been a correlation between rig counts and oil prices driving capital spending in the upstream sector of the energy industry. Likewise, this has typically been an indicator for the performance of the oilfield services (OFS) sector as well.
The onset of 2020 began with an active rig count of 796, down from the peak of 1,075 in January 2019. Post-COVID-19, the rig count declined to 247 and has since rebounded slightly to 269. Pre-COVID-19, the disconnect between rig counts and oil prices was evidenced by the change from 2019 to 2020. Post-COVID-19, the lowest WTI closing price was $16.94/bbl; however, the WTI crude price has since rebounded from historic lows to hover at approximately $40/bbl.
